T-REX OIL, INC. - Annual Report: 2009 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2009

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission file number: 000-51425

RANCHER ENERGY CORP.

(Exact name of registrant as specified in its charter)

Nevada	98-0422451
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

999-18th Street, Suite 3400

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 629-1125

(Telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act:

Title of each class	Name of Each Exchange On Which Registered
Common Stock, par value $0.00001 per share	N/A

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one).

Large accelerated filer	o		Accelerated filer	o
Non-accelerated filer	o	(Do not check if a smaller reporting company)	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter ended September 30, 2008 was $16,722,025.

The number of shares outstanding of the registrant’s common stock as of June 30, 2009 was 119,516,723.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2009 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		PAGE NO.
PART I

ITEM 1.	BUSINESS	2
ITEM 1A.	RISK FACTORS	8
ITEM 1B.	UNRESOLVED STAFF COMMENTS	13
ITEM 2.	PROPERTIES	13
ITEM 3.	LEGAL PROCEEDINGS	16
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	16

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	16
ITEM 6.	SELECTED FINANCIAL DATA	19
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	30
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	30
ITEM 9A(T).	CONTROLS AND PROCEDURES	31
ITEM 9B.	OTHER INFORMATION	32

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	32
ITEM 11.	EXECUTIVE COMPENSATION	33
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	33
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	33
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	33

PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	34

For abbreviations on definitions of certain terms used in the oil and gas industry and in this Annual Report, please refer to the section entitled “Glossary of Abbreviations and Terms” in Item 1 Business.

As used in this document, references to “Rancher Energy”, “our company”, “the Company”, “we”, “us”, and “our” refer to Rancher Energy Corp. and its wholly-owned subsidiary. In this Annual Report, the “Cole Creek South Field” also is referred to as the “South Cole Creek Field”.

PART I

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in this Annual Report on Form 10-K that are not historical are “forward-looking statements”, as that term is defined in Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), that involve a number of risks and uncertainties.

These forward-looking statements include, among others, the following:

business strategy;

ability to complete a sale of the Company, all or a significant portion of its assets or financing or other strategic alternatives;

ability to obtain the financial resources to repay secured debt and to conduct the EOR projects;

water availability and waterflood production targets;

carbon dioxide (CO2) availability, deliverability, and tertiary production targets;

construction of surface facilities for waterflood and CO2 operations and a CO2 pipeline;

inventories, projects, and programs;

other anticipated capital expenditures and budgets;

future cash flows and borrowings;

the availability and terms of financing;

oil reserves;

reservoir response to water and CO2 injection;

ability to obtain permits and governmental approvals;

technology;

financial strategy;

realized oil prices;

production;

lease operating expenses, general and administrative costs, finding and development costs;

availability and costs of drilling rigs and field services;

future operating results; and

plans, objectives, expectations, and intentions.

These statements may be found under “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” and other sections of this Annual Report. Forward-looking statements are typically identified by use of terms such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology, although some forward-looking statements may be expressed differently.

The forward-looking statements contained in this Annual Report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report are not guarantees of future performance and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this Annual Report. All forward-looking statements speak only as of the date of this Annual Report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

ITEM 1. BUSINESS

The Company

We are an independent energy company engaged in the development, production, and marketing of oil and gas in North America. Our business strategy is to use modern tertiary recovery techniques on older, historically productive fields with proven in-place oil and gas. Higher oil and gas prices and advances in technology such as 3-D seismic acquisition and evaluation and carbon dioxide (CO2) injection and sequestration, should position us to capitalize on attractive sources of potentially recoverable oil and gas.

We operate three fields in the Powder River Basin, Wyoming, which is located in the Rocky Mountain region of the United States. The fields, acquired in December 2006 and January 2007, are the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field. All three fields currently produce some oil and are CO2 tertiary recovery candidates. We plan to substantially increase production in our fields by using CO2 injection and other enhanced oil recovery (EOR) techniques. To fund the acquisition of the three fields and our operating expenses, from June 2006 through January 2007, we sold $89,300,000 of our securities in two private placements. In December 2006, we also entered into an agreement with Anadarko Petroleum Corporation (Anadarko) to supply us with CO2 needed to conduct CO2 tertiary recovery operations in our three fields. In February 2008, we entered into a Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas and Power Marketing, (ExxonMobil), a division of ExxonMobil Corporation, to supply additional CO2 to the three fields. We are seeking financing or strategic joint venture partners to enable us to construct a pipeline to deliver CO2 to our fields and to drill additional wells and construct necessary infrastructure improvements in order to implement EOR techniques.

Led by an experienced management team and complimented by a consultant with particular knowledge in each aspect of the EOR process, our long term goal is to enhance stockholder value by identifying and further developing productive oil and gas assets across North America, particularly in the Rocky Mountains. Our headquarters office is located in Denver, Colorado where we employ 5 persons and our field office is located in Glenrock, Wyoming, where we employ 3 persons.

Incorporation and Organization

We were incorporated on February 4, 2004, as Metalex Resources, Inc., in the State of Nevada. Prior to April 2006, we were engaged in the exploration of a gold prospect in British Columbia, Canada. Metalex found no commercially exploitable deposits or reserves of gold. During April 2006, our stockholders voted to change our name to Rancher Energy Corp.

Business Strategy

We need substantial additional funding or to enter into another type of strategic transaction to be able to repay our short term debt and to continue operations. In October 2007 we raised approximately $12.2 million in short-term debt financing to enhance production and provide cash reserves. While we had intended to raise long-term debt in 2007 to further our waterflood and CO2 EOR plans, weakness in the capital market conditions contributed to our change in strategy to raise short-term financing. The raising of future funding is dependent on many factors, some of which are outside our control and are not assured. One major factor is the level of and projected trends in oil prices, which we cannot protect against by using hedging at this time. Our short term debt was originally scheduled to mature on October 31, 2008. On October 22, 2008, we and the Lender entered into an amendment to the credit agreement to extend the maturity for six months until April 30, 2009. One June 3, 2009, we and the Lender further extended the maturity date of the credit agreement to October 15, 2009.

In 2008, we retained a financial advisor to consider financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to survive will be dependent upon completing a strategic transaction; however, there is no assurance that any transaction will be completed

Our short term business strategy includes the following

Continue to explore the potential for a strategic transaction or financing to repay the Company’s debt and to continue operations;

Minimize operating and administration costs;

Enhance crude oil production and initiate development activities in our fields.

Longer term, assuming we are successful in raising the needed capital, we believe in these fundamental business strategies and principles:

Commence the EOR development of our three oil fields;

Pursue attractive reserve and leasehold acquisitions that provide the opportunity for the use of EOR techniques, which offer significant upside potential while not exposing us to risks associated with drilling new field wildcat wells in frontier basins ;

Pursue selective complimentary acquisitions of long-lived producing properties which include a high degree of operating control, and oil and gas entities that offer opportunities to profitably develop oil and gas reserves;

Drive growth through technology and drilling by supplementing long-term reserve and production growth through the use of modern reservoir characterization, engineering, and production technology;

Maximize operational control by operating a significant portion of our assets and continuing to serve as operator of future properties when possible, giving us increased control over costs, timing and all development, production, and exploration activities; and

Pursue strategic alliances with experienced oil and gas development partners to complement our existing asset base and expand our operational capabilities in the Powder River Basin.

If we are unsuccessful in obtaining substantial additional funding or entering into a strategic partnering arrangement before (i) we exhaust our remaining cash on-hand, which is expected to occur by the end of September 2009, and (ii) the maturity of our short term debt in October 2009, we may need to cease operations, our secured lender could foreclose on our properties and/or a bankruptcy filing could be made. If we enter bankruptcy there is no assurance that we will be successful in emerging from bankruptcy.

Property Acquisitions

On December 22, 2006, we purchased certain oil and gas properties for $46,750,000, before adjustments for the period from the effective date to the closing date, plus costs of $323,657 and warrants to purchase 250,000 shares of our common stock. The oil and gas properties consisted of (i) a 100% working interest (79.3% net revenue interest) in the Cole Creek South Field, which is located in Wyoming’s Powder River Basin; and (ii) a 93.6% working interest (74.5% net revenue interest) in the South Glenrock B Field, which also is located in Wyoming’s Powder River Basin.

On January 4, 2007, we acquired the Big Muddy Field, which is located in the Powder River Basin east of Casper, Wyoming. The total purchase price was $25,000,000 and closing costs were $672,638.

Our Development Program

We have completed field studies and economic analysis of the Dakota, Lower Muddy, and Upper Muddy horizons in the South Glenrock B Field and the Wall Creek horizon of the Big Muddy Field and have entered into two CO2 supply agreements. Subject to obtaining additional financing or entering into a strategic partnering arrangement with experienced industry partners, we intend to proceed with the tertiary development of our fields. The current planned order of development is the South Glenrock B Field, the Big Muddy Field, and then the Cole Creek South Field.

Oil and Gas Operations

Our three fields are oil producing, and as further described below in Item 2, are all candidates for EOR operations including CO2 tertiary recovery.

CO2 Tertiary Recovery

Our long term business strategy is to employ modern EOR technology to recover hydrocarbons that remain behind in mature reservoirs. The acquisition of the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field located in the Powder River Basin and entry into the CO2 supply contracts with Anadarko and ExxonMobil were important steps in executing our business strategy. Important next steps are to either secure debt financing, or to enter into a strategic partnering arrangement with an experienced industry partner with the financial resources in a sufficient amount for our development program, complete the required environmental and regulatory permitting, build a pipeline to transport CO2 from an existing CO2 trunk pipeline to the Glenrock area, build out the field infrastructure appropriate for CO2 flood operations, shoot 3-D seismic, if appropriate, and complete the necessary drilling and well work.

CO2 injection is one of the most prevalent tertiary recovery mechanisms for producing light oil. The CO2, at sufficient pressure, acts as a solvent for the oil causing the oil to be physically washed from the reservoir rock and produced. The CO2 is then separated from the oil, compressed and re-injected into the reservoir. This recycling process allows the reuse of the purchased CO2 several times during the life of the tertiary operation. In a typical oil field, much of the original oil in place (OOIP) is left behind after primary production and waterflood operations. In many cases this is in the range of 50% to 75% of the OOIP. This oil, in mature reservoirs with extensive data and historic production, is the target of miscible EOR technology.

Subject to obtaining additional financing or entering into a strategic partnering arrangement with experienced industry partners, we plan to complete an evaluation of the need to conduct a 3-D seismic survey on the South Glenrock B and Big Muddy Fields in conjunction with the CO2 development program. If carried out the seismic information would be used to further define reservoir configuration and trapping, thus filling in gaps in the available information for our fields.

Anadarko CO2 Supply Agreement

As part of our CO2 tertiary recovery strategy, on December 15, 2006, we entered into a Product Sale and Purchase Contract (Purchase Contract) with Anadarko for the purchase of CO2 (meeting certain quality specifications). We intend to use the CO2 for our EOR projects.

The primary term of the Purchase Contract commences upon the later of January 1, 2008, or the date of the first CO2 delivery, which as of June 30, 2009, had not yet occurred and terminates upon the earlier of the day on which we have taken and paid for the Total Contract Quantity, as defined, or 10 years from the commencement date. We have the right to terminate the Purchase Contract at any time with notice to Anadarko, subject to a termination payment as specified in the Purchase Contract.

During the primary term, the “Daily Contract Quantity” is 40 Mmcf per day for a total of 146 Bcf. CO2 deliveries are subject to a 25 Mmcf per day take-or-pay provision. Anadarko has the right to satisfy its own needs before sales to us, which reduces our take or pay obligation. In the event the CO2 does not meet certain quality specifications, we have the right to refuse delivery of such CO2.

For CO2 deliveries, we have agreed to pay $1.50 per thousand cubic feet, to be adjusted by a factor that is indexed to the average posted price of Wyoming Sweet oil. From oil that is produced by CO2 injection, we have also agreed to convey to Anadarko an overriding royalty interest that increases over time, not to exceed 5%.

As of the date of this Annual Report, we are currently in discussions with Anadarko to amend the Purchase Contract to minimize or eliminate certain uncertain provisions and terms of the agreement that are subject to differing interpretations.

ExxonMobil CO2 Supply Agreement

On February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas & Power Marketing Company (ExxonMobil) that is to provide us with 70 MMscfd (million standard cubic feet per day) of CO2 for an initial 10-year period (the “ExxonMobil Agreement”). We intend to use the CO2 for our EOR projects. The primary term of the agreement, which is ten years, will begin the first day of the month following ExxonMobil’s notice to us of the completion of the expansion of certain CO2 delivery facilities by ExxonMobil and that it is prepared to deliver the required daily quantity as required under the agreement. Either party may extend the agreement for an additional ten year term following proper notice and agreement to certain applicable terms of the agreement. Following the commencement of the primary term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of CO2 per day. We have agreed to a “take-or-pay” provision under the agreement. For CO2 deliveries from ExxonMobil, we have agreed to pay a base price plus an Oil Price Factor which is indexed to the price of West Texas Intermediate crude oil.

We may terminate the agreement if ExxonMobil fails to meet our quantity nomination of CO2 (not to exceed 70 MMscfd per day) for 30 consecutive days except under certain circumstances. Either party has the right to terminate the agreement at any time with notice to the other party based on certain circumstances described in the agreement. ExxonMobil is not obligated to commence delivery of CO2 until we provide a surety bond equal to four months’ supply of CO2. ExxonMobil may also request additional financial performance assurances if it has reasonable grounds for believing that we have ceased to have the financial resources to meet our obligations under the agreement and ExxonMobil may suspend delivery of CO2 until the appropriate assurances are provided. ExxonMobil may terminate the agreement if a requested performance assurance is not provided by us within 30 days of a request.

On April 3, 2009, we were informed by ExxonMobil that it was terminating the Agreement based on our failure to provide performance assurances in the form of a letter of credit. We believe that the Agreement does not obligate us to provide any performance assurances until the start-up of CO2 delivery, which will not occur in 2009. Accordingly, we disagree with ExxonMobil’s rationale for purportedly terminating the Agreement and believe in good faith that ExxonMobil’s termination of the Agreement has not occurred pursuant to the terms of the Agreement and is unlawful. We have notified ExxonMobil of our position.

Merit Energy Company, LLC Assignment Agreement

On March 18, 2009, we entered into an Assignment Agreement (the “Assignment”) with Merit Energy Company, LLC, a Delaware limited liability company (“Merit”), for the assignment by us of a portion of our right, title and interest in and to, and the assumption by Merit of our obligations related to, the ExxonMobil Agreement dated as of February 1, 2008. ExxonMobil has consented to the Assignment.

Under the terms of the Assignment, Merit may purchase up to 37.5 MMCF per day of carbon dioxide from ExxonMobil for a two-year term beginning on the Start-up Date, as defined in the ExxonMobil Agreement (the “Initial Merit Term”). ExxonMobil will deliver the contract quantities to the existing delivery point at the interconnect of the ExxonMobil and Merit pipelines near Bairoil, Wyoming.

The terms of the Assignment also provide Merit with an option to purchase an additional 6.5 MMCF per day during the Initial Merit Term. Following the Initial Merit Term, to the extent we are not using for our own tertiary recovery purposes any volumes of carbon dioxide we are otherwise obligated, or able to purchase from ExxonMobil under the Contract, Merit has the option to purchase from us so much of such volumes as is elected by Merit on a monthly basis. If, during any period in which Merit is purchasing carbon dioxide volumes under either of these options, an Event of Default (as defined in the Assignment) occurs, Merit will be entitled to continue to receive the contracted amounts of carbon dioxide from ExxonMobil for the full term of the Assignment and we will be required, at Merit’s sole discretion but subject to ExxonMobil’s rights and remedies under the Contract, to assign our remaining rights under the Contract to Merit.

CO2 Pipeline Construction and CO2 EOR Related Field Development

Under the CO2 contracts described above, we have the responsibility for providing pipeline transportation of purchased CO2 to our project area. We plan to transport purchased CO2 through an 8 or 12-inch pipeline and we are evaluating alternatives to construct and operate the pipeline. We have engaged an engineering firm to study potential routes and configurations. Depending on the final route selection, the pipeline may range from 50 to 132 miles in length and cost estimates range from $50 to $132 million.

We have conducted an analysis of permitting requirements for the pipeline and associated surface facilities and have had discussions with Federal and state regulatory agencies. The shorter of the two proposed pipeline routes is almost entirely on state and privately-owned land, with approximately 0.8 mile on Bureau of Land Management (BLM) land. The BLM portion of the route has been impacted by previous railroad and pipeline development. Based on discussions to date with Federal agencies, we do not anticipate that environmental assessments will be required for the shorter pipeline route or for development of the three oil fields. Approval of permits from the BLM and state regulatory agencies will be required for pipeline construction and field development to proceed. The longer route includes approximately 65 miles on BLM lands and we anticipate we would be required to perform an environmental assessment or an environmental impact study for this route. This longer route has also been impacted by previous pipeline and utility development.

Pipeline construction is expected to take approximately 4 months for the shorter route and up to 9 months for the longer route. A number of long lead time items must be commenced simultaneously to successfully implement our CO2 EOR plans, including, commencing and completing right of way acquisition - estimated 7-12 months; ordering steel pipe, milling the steel pipe, and delivery of steel pipe to the construction site - estimated 6 months; finalizing pipeline engineering - estimated 4-8 months; completing various permitting processes - estimated 6-12 months, and completion of the environmental assessment for the longer route - estimated 12 months. In addition, the CO2 surface facilities equipment must be ordered and then constructed. The lead times for surface facilities equipment can be 9-12 months the majority of which must be installed prior to commencing the CO2 flood. Typically, beginning in November and lasting through March, the Wyoming winter conditions can freeze the ground and make installation and construction of pipelines and surface facilities increasingly more difficult and significantly more expensive.

We continue to evaluate two options to finance construction of the pipeline assuming we are successful in raising sufficient additional funding to continue operating. One option is to have a third party build, own, and operate the CO2 pipeline. This operator would be reimbursed for operating expenses and capital investment by way of a transportation tariff on the CO2 delivered, with the tariff varying as a function of throughput. The second option is for us to construct, own, and operate the pipeline. We would require substantial additional capital for this option. We continue to attempt to either borrow funds in a debt financing or to enter into a strategic partnering arrangement with an experienced industry partner to fund the development of our fields and, if necessary, to fund the construction of the CO2 pipeline. There is no assurance we will be successful either borrowing funds or entering into a strategic partnering arrangement to fund the development of our fields construction of the CO2 pipeline.

Anadarko currently is receiving CO2 for its Salt Creek Field in Wyoming from ExxonMobil through a 125-mile, 16-inch pipeline constructed in 2004. ExxonMobil collects CO2 from its natural gas fields at LaBarge, Wyoming and processes the gas at its Shute Creek gas sweetening plant. ExxonMobil then transports the CO2 to the origin of the pipeline for delivery to Anadarko’s Salt Creek Field. Our contract with Anadarko calls for the delivery of CO2 from a connection point near their Salt Creek Field. Our studies have indicated that a different delivery point along their pipeline would result in a shorter, less expensive pipeline over less difficult terrain. We have engaged in negotiations with Anadarko to modify the delivery point for CO2 and to establish a transportation agreement under which Anadarko would also deliver CO2 purchased from ExxonMobil. We have not been able to reach agreement with Anadarko on either issue. There is no assurance we will be successful in such negotiations and, in the event we are not successful, we may be forced to build the pipeline over the longer, more expensive route.

Financing Plans

Due to our limited capital resources, we must raise funds from external sources to implement our development plans. In October 2007, we borrowed approximately $11 million (after fees and expenses) from GasRock Capital LLC. The loan bears interest at a rate equal to the greater of (a) 12% per annum and (b) the LIBOR rate plus 6% per annum. We are required to make monthly interest payments on the amounts outstanding under this loan. All principal payments and any other unpaid amounts were due on October 31, 2008, which was the maturity date of the loan. Our obligations under the loan are secured by a first priority security interest in all of our properties and assets, including all rights under our oil and gas leases in our three producing fields and all of our equipment on those properties. Prior to the October 31, 2008 maturity date we and the Lender agreed to amend the credit agreement to extend the maturity date to April 30, 2009. As partial consideration for the extended maturity date, we repaid approximately $2.2 million of the outstanding balance leaving a principal balance of $10 million. As more fully discussed later in this annual report, subsequent to March 31, 2009, we and the Lender amended the credit agreement to further extend the maturity date to October 15, 2009.

Due to difficulties in the capital debt markets, fixed term debt financing has been unavailable to us to develop our fields. In November 2007 we began to explore strategic alliances with experienced industry partners under which we would assign a percentage of our interests in the three fields, in exchange for the partner’s investment in the fields. We executed a letter of intent with such a partner in February 2008, the terms of which called for the investment of up to $83.5 million to earn up to a 55% interest in the fields. That letter of intent expired on April 30, 2008. We subsequently entered into a second letter of intent with two different parties which included similar terms for the development of the fields, but which also included provisions for the construction of a pipeline from the source of the ExxonMobil CO2 to our three fields. The letter of intent was terminated effective September 20, 2008.

In August 2008, we retained a financial advisor to consider financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to continue as an operating company is dependent upon raising substantial additional financing or completing a strategic transaction before (i) we exhaust our remaining cash on-hand, which is expected to occur by the end of September 2009, and (ii) the maturity or our short term debt in October 2009; however, there is no assurance that any transaction will be completed.

Federal and State Regulations

Numerous Federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly and substantial penalties may be incurred for noncompliance. The following section describes some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.

Based on current laws and regulations, management believes that we are and will be in substantial compliance with all laws and regulations applicable to our current and proposed operations and that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital costs of complying with the regulations applicable to our operations are uncertain and will be governed by several factors, including future changes to regulatory requirements. However, management does not currently anticipate that future compliance will have a material adverse effect on our consolidated financial position or results of operations.

Regulation of Oil Exploration and Production

Our operations are subject to various types of regulation at the Federal, state, and local levels. Such regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in those units and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells and generally prohibit the venting or flaring of gas. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability.

Federal Regulation of Sales Prices and Transportation

The transportation and certain sales of oil in interstate commerce are heavily regulated by agencies of the U.S. Federal Government and are affected by the availability, terms, and cost of transportation. In particular, the price and terms of access to pipeline transportation are subject to extensive U.S. Federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the oil industry. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the oil and gas industry. The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. Some of FERC’s proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. While our sales of crude oil are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms, and conditions of service are subject to FERC regulation. Additional proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, FERC, state regulatory bodies, and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. Historically, the oil and gas industry has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC, Congress and the states will continue indefinitely into the future.

Federal or State Leases

Our operations on Federal or state oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service (MMS), and other agencies.

Regulation of Proposed CO2 Pipeline

Numerous Federal and state regulations govern pipeline construction and operations. The primary pipeline construction permits may include environmental assessments for Federal lands, right of way permits for fee and state lands, and oversight of ongoing pipeline operations by the U.S. Department of Transportation.

Environmental Regulations

Public interest in the protection of the environment has increased dramatically in recent years. Our oil production and CO2 injection operations and our processing, handling, and disposal of hazardous materials such as hydrocarbons and naturally occurring radioactive materials (NORM) are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

Various Federal, state, and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development, and production operations and consequently may impact our operations and costs. These regulations include, among others (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation and Liability Act, Federal Resource Conservation and Recovery Act, and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal Federal statute governing the treatment, storage, and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage, and disposal of naturally occurring radioactive material.

Management believes that we are in substantial compliance with applicable environmental laws and regulations and intend to remain in compliance in the future. To date, we have not expended any material amounts to comply with such regulations and management does not currently anticipate that future compliance will have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

Competition and Markets

We face competition from other oil companies in all aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, obtaining goods, services, and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties, and our standards established for minimum projected return on investment. Competition is also presented by alternative fuel sources, including ethanol and other fossil fuels.

The demand for qualified and experienced field personnel to operate CO2 EOR techniques, drill wells, and conduct field operations, such as geologists, geophysicists, engineers, and other professionals in the oil industry, can fluctuate significantly often in correlation with oil prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services, and personnel. Higher oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, and services. We cannot be certain when we will experience these issues and these types of shortages or price increases, which could significantly decrease our profit margin, cash flow, and operating results, or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

Available Information

We make our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act available free of charge under the Investors Relations page on our website, www.rancherenergy.com, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. Information on our website or any other website is not incorporated by reference in this Annual Report. Our SEC filings are also available through the SEC’s website, www.sec.gov and may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information regarding the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.

Glossary of Abbreviations and Terms

Anadarko		The Anadarko Petroleum Corporation.

Bcf		One billion cubic feet of natural gas at standard atmospheric conditions.

CO2		Carbon Dioxide.

ExxonMobil		ExxonMobil Gas & Power Marketing Company, a division of ExxonMobil Corporation.

ExxonMobil Agreement		The ExxonMobil Carbon Dioxide Sale and Purchase Agreement.

EOR		Enhanced oil recovery.

Farmout		The transfer of all or part of the working interest in a property, in exchange for the transferee assuming all or part of the cost of developing the property.

Field		An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Growth Capital		Growth Capital Partners, L.P

MMcf		One million cubic feet of natural gas.

MMscfd		One million standard cubic feet per day of natural gas.

Merit		Merit Energy Company, LLC,

Metalex		Metalex Resources, Inc.

Miscible		Capable of being mixed in all proportions. Water and oil are not miscible. Alcohol and water are miscible. CO2 and oil can be miscible under the proper conditions.

Proved reserves		The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Purchase Contract		The Anadarko Product Sale and Purchase Contract.

Tertiary recovery		The third process used for oil recovery. Usually primary recovery is the result of depletion drive, secondary recovery is from a waterflood, and tertiary recovery is an enhanced oil recovery process such as CO2 flooding.

Working interest		An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

ITEM 1A. RISK FACTORS

You should carefully consider the risks described below, as well as the other information included or incorporated by reference in this Annual Report, before making an investment in our common stock. The risks described below are not the only ones we face in our business. Additional risks and uncertainties not presently known or that we currently believe to be immaterial may also impair our business operations. If any of the following risks occur, our business, financial condition, or operating results could be materially harmed. In such an event, our common stock could decline in price and you may lose all or part of your investment.

Risks Related to our Industry, Business and Strategy

If we are unable to obtain additional financing we will be unable to continue operations and to repay our short term debt, our secured lender may foreclose on our properties and/or a bankruptcy filing could be made.

The report of our independent registered public accounting firm on the financial statements for the year ended March 31, 2009 and 2008 includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. Our current cash position will not be sufficient for us to continue operations past September 2009, to repay our short term debt on the maturity date of October 15, 2009 or to fund the development of our three properties for CO2 EOR operations. As a result, we may need to cease operations, our secured lender may foreclose on our properties and/or a bankruptcy filing could be made. There is no assurance that if we enter into the bankruptcy process we will be successful in emerging from bankruptcy.

If we are unable to obtain substantial additional funding or enter into a strategic partnering arrangement, we will be unable to achieve our business plan.

If we are successful in obtaining additional financing to meet our cash requirements and pay-off our short-term debt, we will still require substantial additional funding or need to enter into a strategic partnering arrangement to achieve our business plan . Our plan is to obtain financing or to farmout or enter into another type of transaction to facilitate development of our properties. We have engaged a financial advisor to assist in financing and other strategic alternatives, including the possible sale of the Company. If we are unsuccessful in completing such a strategic transaction, we will need to seek other financing arrangements the availability of which is unknown. The terms of any financing arrangement may be on terms unfavorable to us and could restrict our future business activities and expenditures. A farmout will reduce our ultimate ownership interest in and future cash flows from the properties. Insufficient funds will prevent us from implementing our secondary and tertiary recovery business strategy.

Our October 2007 short-term debt financing, as amended, required the imposition of a mortgage interest in favor of our lender on our three fields and a default by us of the financing terms could result in the foreclosure and loss of one or more of our fields and other assets.

In October 2007, we issued $12,240,000 of short term debt the proceeds of which were intended to enhance our existing production and to provide cash reserves for operations. The debt was scheduled to mature on October 31, 2008. We had planned to secure longer term fixed rate financing to repay the short term debt and to commence our EOR development activities in the three fields of the Powder River Basin; however, due to difficulties in the capital debt markets, we have been unable to secure such financing. On October 2008 we repaid approximately $2.2 million of the debt and we entered into an amendment to the credit agreement to, among other terms, extend the maturity date until April 30, 2009. On April 30,2009, May 8, 2009, May 13, 2009, May 19,2009, May 21, 2009 and May 27, 2009 we entered into amendments that extended the maturity date for short periods of time while we and the Lender finalized negotiations on a longer term extension. On June 3, 2009 we entered into an amendment that, among other things, extended the maturity date to October 15, 2009. We do not have cash available to repay this loan. If we are not successful in repaying this debt within the term of the loan, or default under the terms of the loan, the lender will be able to foreclose one or more of our three properties and other assets and we could lose the properties. A foreclosure could significantly reduce or eliminate our property interests or force us to alter our business strategy, which could involve the sale of properties or working interests in the properties. A foreclosure would adversely affect our results of operations and financial condition including a possible termination of business activities.

ExxonMobil has notified us they have terminated the CO2 Sale and Purchase Agreement.

On April 3, 2009, ExxonMobil informed us, that ExxonMobil was terminating, effective immediately, the CO2 Sale & Purchase Agreement. ExxonMobil’s purported termination is based on our failure to provide performance assurances in the form of a letter of credit. We disagree with ExxonMobil’s rationale for purportedly terminating the Agreement and believe in good faith that Exxon’s termination of the Agreement has not occurred pursuant to the terms of the Agreement and is unlawful. If ExxonMobil does not deliver CO2 in accordance with the Sale & Purchase Agreement, we may not be able to fully carry out our EOR projects on our three fields.

Our contracts with our CO2 suppliers include significant take-or-pay obligations.

Our existing contracts with ExxonMobil and Anadarko contain provisions under which we are required to take delivery of certain volumes of CO2 or pay the seller for the volume difference between the required quantity and the volume actually purchased. If we are unable to secure sufficient financing to construct a pipeline and to develop and prepare our properties for the injection of CO2 we will be unable to take delivery of CO2 and our cash position at that time will not be sufficient to pay for the take-or-pay volumes.

We have incurred losses from operations in the past and expect to do so in the future.

We have never been profitable. We incurred net losses of $46,341,341 and $13,164,826 for the fiscal years ended March 31, 2009 and 2008, respectively. We do not expect to be profitable during the fiscal year ending March 31, 2010 Our acquisition and development of prospects will require substantial additional capital expenditures in the future. The uncertainty and factors described throughout this section may impede our ability to economically acquire, develop, and exploit oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

We may not be able to develop the three Powder River Basin properties as we anticipate.

Our plans to develop the properties are dependent on the construction of a CO2 pipeline and a sufficient supply of CO2. We must arrange for the construction of a CO2 pipeline on acceptable terms and build related infrastructure. The achievement of these objectives is subject to numerous uncertainties, including the raising of sufficient funding for the construction of key infrastructure and working capital and our reliance on a third party to provide us the requisite CO2, the supply of which is beyond our control. We may not be able to achieve these objectives on the schedule we anticipate or at all.

Our production is dependent upon sufficient amounts of CO2and will decline if our access to sufficient amounts of CO2 is limited.

Assuming we are successful in raising sufficient financing, our long-term growth strategy is focused on our CO2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO2. Our ability to produce this oil would be hindered if our supply of CO2 were limited due to problems with the supply, delivery, quality of the supplied CO2, problems with our facilities, including compression equipment, or catastrophic pipeline failure. We have received no CO2 to date. We have agreements with two CO2 suppliers. Our agreement with one of our suppliers of CO2 is complex and subject to differing interpretations. It provides that before it delivers CO2 to us, it may satisfy its own CO2 needs. We also have had discussions with that supplier regarding a different delivery point that is not resolved. If we are not successful in obtaining the required amount of CO2 to achieve crude oil production or the crude oil production in the future were to decline as a result if a decrease in delivered CO2 supply, it could have a material adverse effect on our financial condition and results of operations and cash flows.

Our development and tertiary recovery operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil reserves.

The oil industry is capital intensive. We have made and are required to make substantial capital expenditures in our business and operations for the development, production, and acquisition of oil and gas reserves. To date, we have financed capital expenditures primarily with sales of our equity securities. We intend to finance our capital expenditures with debt financing or to enter into a strategic alliance with experienced operators who have access to sufficient capital to carry out our EOR projects. As of the date of this Annual Report, we have not been successful in achieving the foregoing. Our access to capital is subject to a number of variables, including:

our proved reserves;

the amount of oil we are able to produce from existing wells;

the prices at which the oil is sold; and

our ability to acquire, locate and produce new reserves.

We may, from time to time, need to seek additional financing, either in the form of increased bank borrowings, sales of debt or equity securities or other forms of financing and there can be no assurance as to the availability or terms of any additional financing. Additionally, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. A failure to obtain additional financing to meet our capital requirements could result in a curtailment of our operations relating to our tertiary recovery operations and development of our fields, which in turn could lead to a possible loss of properties, through foreclosure, if we are unable to meet the terms of our anticipated debt financing and/or forfeiture of the properties pursuant to the terms of their respective leases and a decline in our oil reserves.

We plan to conduct our secondary and tertiary recovery operations on older fields that may be significantly depleted of oil, which could lead to an adverse impact on our future results.

We operate three fields in the Powder River Basin, Wyoming. Oil in all three fields was discovered over fifty years ago and production has been ongoing. Our strategy is to substantially increase production and reserves in these fields by using waterflood and CO2 EOR techniques. However, there is a risk that the properties may be significantly depleted of oil, and if so, our future results could be impacted negatively.

We have a limited operating history in the oil business and we cannot predict our future operations with any certainty.

We were organized in 2004 to explore a gold prospect and in 2006 changed our business focus to oil and gas development using CO2 injection technology. Our future financial results depend primarily on (i) our ability to finance and complete development of the required infrastructure associated with our three properties in the Powder River Basin, including having a pipeline built to deliver CO2 to our fields and the construction of surface facilities on our fields; (ii) the success of our CO2 injection program; and (iii) the market price for oil. We cannot predict that our future operations will be profitable. In addition, our operating results may vary significantly during any financial period.

Oil prices are volatile and a decline in oil prices can significantly affect our financial results and impede our growth.

Our revenues, profitability, and liquidity are substantially dependent upon prices for oil, which can be extremely volatile; and, even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices for oil may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, market uncertainty, and a wide variety of additional factors that are beyond our control, such as the domestic and foreign supply of oil, the price of foreign imports, the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls, technological advances affecting energy consumption, domestic and foreign governmental regulations, and the variations between product prices at sales points and applicable index prices.

We could be adversely impacted by changes in the oil market.

The marketability of our oil production will depend in part upon the availability, proximity, capacity of pipelines, and surface and processing facilities. Federal and state regulation of oil production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect our ability to produce and market oil. If market factors were to change dramatically, the financial impact could be substantial because we would incur expenses without receiving revenues from the sale of production. The availability of markets is beyond our control.

We may be unable to develop additional reserves.

Our ability to develop future revenues will depend on whether we can successfully implement our planned CO2 injection program. We have no experience using CO2 technology. The Company's properties have not been injected with CO2 in the past and recovery factors cannot be estimated with precision. Our planned projects may not result in significant proved reserves or in the production levels we anticipate.

We are dependent on our management team and the loss of any of these individuals would harm our business.

Our success is dependent, in large part, on the continued services of John Works, our President & Chief Executive Officer, Richard Kurtenbach our Chief Accounting Officer and Denise Greer our Land and Operations Manager. There is no guarantee that any of the members of our management team will remain employed by us. While we have employment agreements with them, their continued service cannot be assured. The loss of our senior executives could harm our business.

Oil operations are inherently risky.

The nature of the oil business involves a variety of risks, including the risks of operating hazards such as fires, explosions, cratering, blow-outs, encountering formations with abnormal pressure, pipeline ruptures, and spills, releases of toxic gas and other environmental hazards and pollution. The occurrence of any of these risks could result in losses. The occurrence of any one of these significant events, if it is not fully insured against, could have a material adverse effect on our financial position and results of operations.

We are subject to extensive government regulations.

Our business is affected by numerous Federal, state, and local laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil industry. These include, but are not limited to:

the prevention of waste;

the discharge of materials into the environment;

the conservation of oil;

pollution;

permits for drilling operations;

underground gas injection permits;

drilling bonds; and

reports concerning operations, the spacing of wells, and the unitization and pooling of properties.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

Government regulation and environmental risks could increase our costs.

Many jurisdictions have at various times imposed limitations on the production of oil by restricting the rate of flow for oil wells below their actual capacity to produce. Our operations will be subject to stringent laws and regulations relating to environmental issues. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentration of materials that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities in protected areas and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently and changes could result in substantially increased costs. Because current regulations covering our operations are subject to change at any time, we may incur significant costs for compliance in the future.

The properties we have acquired are located in the Powder River Basin in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our activities are focused on the Powder River Basin in the Rocky Mountain Region of the United States, which means our properties are geographically concentrated in that area. As a result, we may in the future be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, or interruption of transportation of oil produced from the wells in this basin.

Seasonal weather conditions adversely affect our ability to conduct drilling activities and tertiary recovery operations in some of the areas where we operate.

Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and gas activities can only be conducted during the spring and summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies, and qualified personnel, which may lead to periodic shortages. Resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.

The oil and gas industry is intensely competitive and we compete with companies that are significantly larger and have greater resources. Many of these companies not only explore for and produce oil, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for oil properties and prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. Our larger competitors may be able to absorb the burden of present and future Federal, state, local, and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to increase reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Oil prices may be impacted adversely by new taxes.

The Federal, state, and local governments in which we operate impose taxes on the oil products we plan to sell. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. In addition, many states have raised state taxes on energy sources and additional increases may occur. We cannot predict whether any of these measures would have an adverse impact on oil prices.

Shortages of equipment, supplies, personnel, and delays in construction of the CO2pipeline, construction of surface facilities, and delivery of CO2 could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.

We may experience shortages of field equipment and qualified personnel and delays in the construction of the CO2 pipeline, construction of surface facilities, and delivery of CO2, which may cause delays in our ability to conduct tertiary recovery operations and drill, complete, test, and connect wells to processing facilities. Additionally, these costs have sharply increased in various areas. The demand for and wage rates of qualified crews generally rise in response to the increased number of active rigs in service and could increase sharply in the event of a shortage. Shortages of field equipment or qualified personnel, delays in the construction of the CO2 pipeline, construction of surface facilities, and delivery of CO2 could delay, restrict, or curtail our exploration and development operations, which may materially adversely affect our business, financial condition, and results of operations.

Shortages of transportation services and processing facilities may result in our receiving a discount in the price we receive for oil sales or may adversely affect our ability to sell our oil.

We may experience limited access to transportation lines, trucks or rail cars in order to transport our oil to processing facilities. We may also experience limited processing capacity at our facilities. If either or both of these situations arise, we may not be able to sell our oil at prevailing market prices or we may be completely unable to sell our oil, which may materially adversely affect our business, financial condition, and results of operations.

Estimating our reserves, production and future net cash flow is difficult to do with any certainty.

Estimating quantities of proved oil and gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and gas industry in general is subject. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could result in a reduction of the quantities and net present value of our reserves.

Quantities of proved reserves are estimated based on economic conditions, including oil and gas prices in existence at the date of assessment. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and gas prices, as well as due to production results, results of future development, operating and development costs, and other factors. Downward revisions of our reserves could have an adverse affect on our financial condition, operating results, and cash flows.

Risks Related to our Common Stock

The trading market for our common stock is very limited, so there is limited liquidity in our common stock and investors may be unable to sell significant numbers of shares of our stock.

Although our common stock is currently traded on the OTC Bulletin Board, it is thinly traded. It has been traded on the OTC Bulletin Board since early 2006. The average daily trading volume of our common stock on the OTC Bulletin Board was approximately 152,000 shares per day over the three month period ended March 31, 2009. We cannot be certain that more of a market for our common stock will develop, or if developed, that it will be sustained, or that our stock price will increase. As a result, investors cannot expect to liquidate their investments in an orderly manner regardless of the necessity of doing so. If we are unable to sustain a market for our common stock, investors may be unable to sell the common stock they own, and may lose the entire value of their investment.

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market of our common stock could change in ways that may or may not be related to our business, our industry, or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

Actual or anticipated quarterly variations in our operating results;

Changes in expectations as to our future financial performance or changes in financial estimates, if any;

Announcements relating to our business or the business of our competitors;

Conditions generally affecting the oil and gas industry;

The success of our operating strategy; and

The operating and stock performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. If the market price of our common stock declines significantly, you may be unable to resell your shares of common stock at or above the price you acquired those shares. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly.

There are risks associated with forward-looking statements made by us and actual results may differ.

Some of the information in this Annual Report contains forward-looking statements that involve substantial risks and uncertainties. These statements can be identified by the use of forward-looking words such as “may”, “will”, “expect”, “anticipate”, “believe”, “estimate”, and “continue”, or similar words. Statements that contain these words should be read carefully because they:

discuss our future expectations;

contain projections of our future results of operations or of our financial condition; and

state other “forward-looking” information.

We believe it is important to communicate our expectations. However, there may be events in the future that we are not able to accurately predict and/or over which we have no control. The risk factors listed in this section, other risk factors about which we may not be aware, as well as any cautionary language in this Annual Report, provide examples of risks, uncertainties, and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. The occurrence of the events described in these risk factors could have an adverse affect on our business, results of operations, and financial condition.

Our failure to maintain effective internal control over financial reporting may not allow us to accurately report our financial results, which could cause our financial statements to become materially misleading and adversely affect the trading price of our stock.

In our annual reports on Form 10-K for the fiscal years ended March 31, 2009 and 2008, we reported the determination of our management that we had a material weakness in our internal control over financial reporting. The determination was made by management that we did not adequately segregate duties of different personnel in our accounting department due to an insufficient complement of staff and inadequate management oversight. While we have made progress in remediating the weakness, we have not completely remediated it, primarily due to limited resources to add experienced staff. Until we obtain sufficient financing we will not be able to correct the material weakness in our internal control over financial reporting, and our business could be harmed and the stock price of our common stock could be adversely affected.

FINRA sales practice requirements limit a stockholders' ability to buy and sell our stock.

The Financial Industry Regulatory Authority, Inc. (FINRA) has adopted rules which require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives, and other information. Under interpretations of these rules, the FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which has the effect of reducing the level of trading activity and liquidity of our common stock. Further, many brokers charge higher transactional fees for penny stock transactions. As a result, fewer broker-dealers are willing to make a market in our common stock, reducing a stockholders' ability to resell shares of our common stock.

We do not expect to pay dividends in the foreseeable future. As a result, holders of our common stock must rely on stock appreciation for any return on their investment.

We do not anticipate paying cash dividends on our common stock in the foreseeable future. Any payment of cash dividends will also depend on our financial condition, results of operations, capital requirements, and other factors and will be at the discretion of our Board of Directors. We also expect that if we obtain debt financing, there will be contractual restrictions on, or prohibitions against, the payment of dividends. Accordingly, holders of our common stock will have to rely on capital appreciation, if any, to earn a return on their investment in our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Field Summaries

We currently operate three fields in the Powder River Basin: the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field. The concentration of value in a relatively small number of fields should allow us to benefit substantially from any operating cost reductions or production enhancements we achieve and allows us to effectively manage the properties from our field office located in Glenrock, Wyoming.

South Glenrock B Field

The South Glenrock B Field is in Wyoming’s Powder River Basin and is located in Converse County, about 20 miles east of Casper in the east-central region of the state. The field was discovered by Conoco, Inc.

The South Glenrock B Field produces primarily from the Lower and Upper Muddy formations as well as the Dakota formation. All the formations are Cretaceous fluvial deltaic sands with extensive high reservoir quality channels. The structure dips from west to east with approximately 2,000 feet of relief.

The South Glenrock B Field is an active waterflood that currently produces approximately 80 BOPD of sweet 35 degree API crude oil. There are 10 active producing wells. This waterflood unit was developed with a fairly regular 40 acre well spacing and drilled with modern rotary equipment. The South Glenrock B Field is slated to be the first of our fields for CO2 development because the waterflood has maintained the reservoir pressure high enough for CO2 operations and the relative condition of the facilities, regular well spacing, and reservoir size make the field a good candidate for CO2 operations. Subject to obtaining financing, we plan to start CO2 injection in the South Glenrock B Field in calendar year 2011

Big Muddy Field

The Big Muddy Field is in Wyoming’s Powder River Basin and located in Converse County, 17 miles east of Casper in the east-central region of the state. The field was discovered in 1916 and has produced approximately 52 million barrels of oil from several producing zones including the First Frontier, Stray, Shannon, Dakota, Lakota, Muddy and Niobrara formations. The Big Muddy Field was waterflooded starting in 1957.

The Big Muddy Field is currently producing about 30BOPD of 36 degree API sweet crude oil, via a stripper operation, from four producing wells. The field was developed with an irregular well spacing and drilled mostly with cable tools. There are no facilities of any significance at the field.

The current reservoir pressure is very low and not sufficient for effective CO2 flooding. Pending financing, our near-term plans for the Big Muddy Field are to build facilities and reactivate or drill new injection wells in order to inject disposal water produced as a result of CO2 operations in the South Glenrock B Field. The injection of this water should have the effect of raising the Big Muddy reservoir pressure for the planned CO2 flood. We also hope to drill or reactivate additional production wells in order to produce more oil from this reactivated waterflood. The Big Muddy Field requires unitization prior to a waterflood or a CO2 flood. The State of Wyoming required us to form two separate units, one for the Wall Creek formation and one for the Dakota formation, due to the different sizes of the productive horizons. The unitization was completed in calendar year 2008 and subject to obtaining financing; we plan to start CO2 injection in the Big Muddy Field within one to two years after commencing CO2 injection in the South Glenrock B Field.

Cole Creek South Field

The Cole Creek South Field is in Wyoming’s Powder River Basin and is located in Converse and Natrona counties, about 15 miles northeast of Casper in the east-central region of the state. The Cole Creek South Field was discovered in 1948 by the Phillips Petroleum Company.

Production at Cole Creek South was originally discovered on structure in the Lakota sandstone. After drilling a number of wells along the crest of the structure that had high water cuts, the Lakota zone was not developed in favor of the Dakota sandstone. Injection into the Dakota formation began in December 1968 and reached peak production in April 1972.

Production comes from two units at Cole Creek South. One unit is the Dakota Sand Unit which is under active waterflood. The other unit is the Cole Creek South Unit which is a primary production unit. Cole Creek South Field produces, in total, approximately 100 BOPD of 34 degree API sweet crude oil from8 producing wells. Production is from the Dakota Sand Unit waterflood and from the Shannon, First Frontier, Second Frontier, Muddy, and Lakota formations.

The Cole Creek South Field is presently at reservoir pressure sufficient for miscible CO2 flooding and the wells are in good working condition. Due to the small size, in comparison to the South Glenrock B Field and the Big Muddy Field, the Cole Creek South Field is planned to be the last of these three fields to undergo CO2 flooding. Subject to obtaining financing, we plan to start CO2 injection in the Cole Creek South Field in within four to five years after commencing CO2 injection in the South Glenrock B Field.

Oil and Gas Acreage and Productive Wells

Our three properties in the Powder River Basin consist of the following acreage.

Field	Gross		Net		Gross		Net		Gross		Net

Big Muddy Field		1,640		972		8,920		8,908		10,560		9,880
South Glenrock B Field		10,873		10,177		-		-		10,873		10,177
Cole Creek South Field		3,782		3,782		-		-		3,782		3,782

Total		16,295		14,931		8,920		8,908		25,215		23,839

We have producing wells located in our three Powder River Basin properties as identified below.

Field	Number of Gross Oil Wells		Number of Net Oil Wells

Big Muddy Field		6	6.00
South Glenrock B Field		13	12.19
Cole Creek South Field		8	8.00
Total Wells		27	26.19

Production

The following table summarizes average volumes and realized prices of oil produced from our properties and our production costs per barrel of oil.

	For the Year Ended March 31,2009		For the Year Ended March 31,2008

Net oil production (barrels)		65,308		86,626
Average realized oil sales price per barrel	$	78.71	$	73.24
Production costs per barrel:
Production taxes	$	9.92	$	8.91
Lease operating expenses	$	37.10	$	33.55

Title to Properties

As customary in the oil and gas industry, during acquisitions, substantive title reviews and curative work are performed on all properties. Generally, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted and curative work is performed with respect to significant defects. We believe that we have good title to our oil and gas properties, some of which are subject to minor encumbrances, easements, and restrictions.

Environmental Assessments

We are cognizant of our environmental responsibilities to the communities in which we operate and to our shareholders. Prior to the closing of our acquisitions, we obtained a Phase I environmental review of our properties from industry-recognized environmental consulting firms. These environmental reviews were commissioned and received prior to our acquisition of our three Wyoming fields, which revealed no material environmental problems. As part of our plans to construct a pipeline to transport CO2 to our fields we will be required to perform either an environmental assessment or a more comprehensive environmental impact study of the proposed pipeline.

Geographic Segments

All of our operations are in the continental United States.

Significant Oil and Gas Purchasers and Product Marketing

Due to the close proximity of our fields to one another, oil production from our three properties is sold to one purchaser under a month-to-month contract at the current area market price. The oil is currently transported by truck to pipeline connections in the area. The loss of that purchaser is not expected to have a material adverse effect upon our oil sales. We currently produce a nominal amount of natural gas, which is used in field operations and not sold to third parties.

Our ability to market oil depends on many factors beyond our control, including the extent of domestic production and imports of oil, the proximity of our oil production to pipelines, the available capacity in such pipelines, refinery capacity, the demand for oil, the effects of weather, and the effects of state and Federal regulation. Our production is from fields close to major pipelines and established infrastructure. As a result, we have not experienced any difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing

The oil production from our properties is relatively high quality, ranging in gravity from 34 to 36 degrees, and is low in sulfur. We sell our oil to a crude aggregator on a month-to-month term. The oil is transported by truck, with loads picked up daily. The prices we currently receive are based on posted prices for Wyoming Sweet crude oil, adjusted for gravity, plus approximately $1.70 to $2.30 per barrel.

Our long-term strategy is to find a dependable future transportation option to transport our high-quality oil to market at the highest price possible and to protect ourselves from downward pricing volatility. Options being explored include building a new crude oil pipeline to connect to a pipeline being considered by others for construction that is anticipated to run from Northern Colorado to Cushing, Oklahoma to transport Wyoming Sweet crude oil.

ITEM 3. LEGAL PROCEEDINGS

On December 31, 2008, we received a letter from an attorney representing Sergei Stetsenko and other shareholders (the “Stetsenko Group”) stating that it was the opinion of the Stetsenko Group that our Directors and Executive Officers have acted negligently and contrary to their fiduciary duties. The letter threatens a lawsuit and demands that the Directors and our Executive Officers return all cash and stock received from us, cease payment of any cash or stock compensation for their services, resign their positions as Directors and Executive Officers and call a shareholders meeting to elect Andrei Stytsenko as the sole director of the Company. No suit has been filed. We deny the allegations and believe that they are without merit. In February 2009, our Board of Directors established a Special Committee of the Board (the “Special Committee”) to investigate the allegations. The Stetsenko Group has informed us that it intends to propose an alternate slate of directors at the next meeting of shareholders. We cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit.

In a letter dated February 18, 2009 sent to each of our Directors, attorneys representing a group of persons who purchased approximately $1,800,000 of securities (in the aggregate) in our private placement offering commenced in late 2006 alleged that securities laws were violated in that offering. Subsequent to March 31, 2009, we entered into tolling agreements with the purchasers to toll the statutes of limitations applicable to any claims related to the private placement. Our Board of Directors directed the Special Committee to investigate these allegations. We believe the allegations are without merit. We cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Common Stock has been quoted on the OTC Bulletin Board under the symbol “RNCH” since January 10, 2006. For the periods indicated, the following table sets forth the high and low bid prices per share of our common stock as reported by the OTC Bulletin Board. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions.

Fiscal Year 2009	High Bid		Low Bid
First Quarter	$	0.53	$	0.31
Second Quarter	$	0.30	$	0.11
Third Quarter	$	0.16	$	0.02
Fourth Quarter	$	0.04	$	0.02
Fiscal Year 2008
First Quarter	$	1.30	$	0.68
Second Quarter	$	0.75	$	0.31
Third Quarter	$	0.84	$	0.20
Fourth Quarter	$	0.69	$	0.26

Stock Performance Graph

The first day of public trading of our common stock was January 10, 2006. The graph below matches the cumulative total return since January 10, 2006 (or December 31, 2005 for the indexes) of holders of our common stock with the cumulative total returns of the NASDAQ Composite Index and the Dow Jones Wilshire MicroCap Exploration and Production Index. The graph assumes that the value of the investment in our common stock and in each of the indexes (including reinvestment of dividends) was $100 on January 10, 2006 (or December 31, 2005 for the indexes) and tracks it through March 31, 2009. The reported closing stock price for our common stock on January 10, 2006 was $0.012143, adjusting for a stock dividend which occurred after that date in January 2006, noted under “Dividends” below.

Stock Performance Graph Data
	1/10/06	3/31/06	3/31/07	3/31/08	3/31/09
Rancher Energy	100.0	11,858.7	10,952.8	3,211.73	164.83
NASDAQ Composite	100.0	106.8	112.3	104.67	69.83
Dow Jones Wilshire – MicroCap Exploration and Production	100.0	108.3	86.7	69.50	20.78

Holders

As of June 17, 2009, there were approximately 201 record owners of our Common Stock. This does not include any beneficial owners for whom shares may be held in “nominee” or “street name”.

Dividends

We have not paid any cash dividends on our Common Stock since inception and we do not anticipate declaring or paying any dividends at any time in the foreseeable future. In January 2006, we conducted a 14-for-1 forward stock split.

Recent Sales of Unregistered Securities

On May 15, 2006, in conjunction with his employment, we granted John Works, our President, Chief Executive Officer, and a member of our Board of Directors, an option to purchase 4,000,000 shares of our common stock at a price of $0.00001 per share. These options vested over time through May 31, 2009. The table that follows summarizes the exercise of Mr. Works’ options during the year ended March 31, 2009:

Exercise Date	Number of Options Exercised		Exercise Price		Aggregate Purchase Price
June 2, 2008		250,000	$	0.00001	$	2.50
September 4, 2008		250,000	$	0.00001	$	2.50
December 12, 2008		250,000	$	0.00001	$	2.50

Mr. Works is an accredited investor. The foregoing transaction was made pursuant to Section 4(2) of the Securities Act.

Pursuant to a Board of Directors resolution adopted April 20, 2007, Directors may receive common stock in lieu of cash for Board Meeting Fees, Committee Fees and Committee Chairman Fees. The number of shares granted under the terms of the resolution were computed based upon the amount of fees due to the directors and the fair market value of our common stock on the date of issuance. The following table summarizes issuances of common stock pursuant to such resolution:

Date of Issue	Number of Shares Issued			Fair Market Value Per Share at Issue Date
Jun 30, 2008		239,514		$	0.31
Sep 30, 2008		495,000		$	0.15
Dec 31, 2008		2,653,845		$	0.026
Mar 31, 2009		0	*	$	N/A

The foregoing transactions were made pursuant to Section 4(2) of the Securities Act.

*All of the non-employee directors elected to forego stock compensation for the quarter ended March 31, 2009.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

We must raise substantial financing by the end of September 2009 before we exhaust our cash on-hand to be able to continue operations and to repay short term debt due in October 2009. As noted elsewhere in this Annual Report, we continue to attempt to raise debt or equity financing or to complete a strategic partnering arrangement; however, there is no assurance we will be able complete a transaction in the next three months.

Organization

We are an independent energy company that explores for and develops, produces, and markets oil and gas in North America. We were known as Metalex Resources, Inc. until April 2006 when our name was changed to Rancher Energy Corp. We operate three oil fields in the Powder River Basin, Wyoming. Our business plan is to use CO2 injection to increase oil production in these oil fields.

Oil and Gas Property Acquisitions

The following is a summary of the property acquisitions we have completed:

Cole Creek South Field and South Glenrock B Field Acquisitions

On December 22, 2006, we purchased certain oil and gas properties for $46,750,000, before adjustments for the period from the effective date to the closing date, plus closing costs of $323,657. The oil and gas properties consisted of (i) a 100% working interest (79.3% net revenue interest) in the Cole Creek South Field, which is located in Wyoming’s Powder River Basin; and (ii) a 93.6% working interest (74.5% net revenue interest) in the South Glenrock B Field, which also is located in Wyoming’s Powder River Basin. In partial consideration for an extension of the closing date, we issued the seller of the oil and gas properties warrants to acquire 250,000 shares of our common stock for $1.50 per share for a period of five years. The estimated fair value of the warrants to purchase common stock of $616,140 was estimated as of the grant date using the Black-Scholes option pricing model and is included in the acquisition cost.

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	46,750,000
Direct acquisition costs		323,657
Estimated fair value of warrants to purchase common stock		616,140
Total	$	47,689,797

Allocation of acquisition costs:
Oil and gas properties:
Unproved	$	31,569,778
Proved		16,682,101
Other assets - long-term accounts receivable		53,341
Other assets - inventory		227,220
Asset retirement obligation		(842,643	)
Total	$	47,689,797

The Cole Creek South Field is located in Converse County, Wyoming approximately six miles northwest of the town of Glenrock. The field was discovered in 1948 by the Phillips Petroleum Company. Current gross production from the Cole Creek South Field is approximately 100 barrels of oil per day (BOPD) of primarily 34 degree API sweet crude oil.

The South Glenrock B Field is also located in Converse County, Wyoming. The field was discovered in 1950 by Conoco, Inc. Bisected by Interstate 25, the field produces from the Dakota and Muddy sandstone reservoirs that are draped over a structural nose with 2,000 feet of relief. Production is maintained by secondary recovery efforts that were initiated in 1961. Current gross production from the South Glenrock B Field is approximately 80 BOPD of primarily 35 degree API sweet crude oil.

Big Muddy Field Acquisition

On January 4, 2007, we acquired the Big Muddy Field, which is located in the Powder River Basin east of Casper, Wyoming. The total purchase price was $25,000,000 and closing costs were $672,638. While the Big Muddy Field was discovered in 1916, future profitable operations are dependent on the application of tertiary recovery techniques requiring significant amounts of CO2.

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	25,000,000
Direct acquisition costs		672,638
Total	$	25,672,638

Allocation of acquisition costs:
Oil and gas properties:
Unproved	$	24,151,745
Proved		1,870,086
Asset retirement obligation		(349,193	)
Total	$	25,672,638

Water flooding was initiated in the Wall Creek formation in 1957 and later expanded to the Dakota and Lakota formations. Over 800 completions have occurred in the field. At the current time, only a few wells are active. The current production is approximately 30 BOPD of primarily 36 degree API sweet crude oil.

Outlook for the Coming Year

We must raise substantial financing by the end of September 2009 to be able to continue operations. Assuming we are successful in raising sufficient financing to meet our cash needs and repay our short-term debt due in October 2009, the following summarizes our goals and objectives for the next twelve months:

	·	Maintain and enhance crude oil production from our existing wells;
	·	Secure long term financing or strategic partnering arrangements with experienced industry partners to enable us to initiate development activities in our fields;
	·	Renew discussions with ExxonMobil to ensure sufficient quantities of CO2 will be made available under the existing Sale and Purchase Agreement or negotiate a new contract with ExxonMobil for the supply of CO2 to our three oil fields.
	·	Continue dissussions with Anadarko to amend the Anadarko Purchase Contract to minimize or eliminate uncertainty.

In late 2006 we added operating staff and engaged consultants to conduct field studies of tertiary development of the three Powder River Basin fields. Through the early part of 2008 work has focused on field and engineering studies to prepare for development operations. We also engaged an engineering firm to evaluate routes and undertake the required front end engineering and design for the required CO2 pipeline, as well as another engineering firm to evaluate and design surface facilities appropriate for CO2 injection. In 2008 we entered into two separate letters of intent with experienced industry partners, each of which called for them invest a significant amount to earn a majority interest in our three fields. Both letters of intent expired before closing a transaction. In anticipation of finalizing an arrangement with industry partners, under which a partner would provide financing and operational control of our fields, we reduced our operating staff in late March 2008. If we are not successful in consummating a transaction with an industry partner, we will need to obtain other sources of financing. Our plans for EOR development of our oil fields are dependent on our obtaining substantial additional funding. In October 2007 we raised approximately $12.2 million in short-term debt financing to enhance production and provide cash reserves. While we had intended to raise a long-term debt financing in 2007 to further our waterflood and CO2 EOR plans, weakness in the capital market conditions contributed to our change in strategy to raise the short-term financing first, followed by either long-term debt financing, or a strategic partnering arrangement with experienced industry partners. The raising of future funding is dependent on many factors, some of which are outside our control and is not assured. One major factor is the level of and projected trends in oil prices, which we cannot protect against by using hedging at this time.

In 2008, we retained a financial advisor to assist in financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to continue operations is dependent upon completing a strategic transaction; however, there is no assurance that any transaction will be completed.

If we are successful in raising financing or closing a strategic partnering arrangement, we plan to begin CO2 development operations in the South Glenrock B Field followed by the Big Muddy Field and then Cole Creek South Field. Capital expenditures to implement our CO2 EOR plan include:

Construct a pipeline to transport CO2 from the source to our South Glenrock B Field at a cost of approximately $50 to $132 million;

Acquire and construct surface facilities at our South Glenrock B Field to inject and recycle CO2 at a cost of approximately $8.5 million;

Drill, complete and equip 70-80 wells as CO2 injectors or oil producers on our South Glenrock B Field at a cost of approximately $48 million;

Drill, complete and equip 70 wells as water injectors or oil producers on our Big Muddy Field at a cost of approximately $46 million; and

Acquire and construct waterflood surface facilities, at a cost of approximately $11.5 million.

If we are successful closing a strategic partnering arrangement with experienced industry partners, we anticipate those partners would be responsible for financial and operational control of pipeline construction and field development for up to three years, after which we would again be responsible for our share of future development expenditures.

Since the acquisition of the three fields, other than the agreements with Anadarko and ExxonMobil for supply of CO2, we have made neither major capital expenditures nor any firm commitments for future capital expenditures to date.

Commitments

Anadarko CO2 Supply Agreement

As part of our CO2 tertiary recovery strategy, on December 15, 2006, we entered into a Product Sale and Purchase Contract with Anadarko for the purchase of CO2 (meeting certain quality specifications) from Anadarko. We intend to use the CO2 for our EOR projects.

The primary term of the Purchase Contract commences upon the later of January 1, 2008, or the date of the first CO2 delivery and terminates upon the earlier of the day on which we have taken and paid for the Total Contract Quantity, as defined, or 10 years from the commencement date. We have the right to terminate the Purchase Contract at any time with notice to Anadarko, subject to a termination payment as specified in the Purchase Contract.

During the primary term the “Daily Contract Quantity” is 40 Mmcf per day for a total of 146 Bcf. Carbon dioxide (CO2) deliveries are subject to a 25 Mmcf per day take-or-pay provision. Anadarko has the right to satisfy its own needs before sales to us, which reduces our take-or-pay obligation. In the event the CO2 does not meet certain quality specifications, we have the right to refuse delivery of such CO2.

For CO2 deliveries we have agreed to pay $1.50 per thousand cubic feet, to be adjusted by a factor that is indexed to the price of Wyoming Sweet oil. From oil that is produced by CO2 injection, we also agreed to convey to Anadarko an overriding royalty interest that increases over time, not to exceed 5%.

ExxonMobil CO2 Supply Agreement

On February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas & Power Marketing Company, a division of ExxonMobil Corporation, which is to provide us with 70 MMscfd (million standard cubic feet per day) of CO2 for an initial 10-year period. We intend to use the CO2 for our EOR projects. The primary term of the agreement, which is ten years, will begin the first day of the month following ExxonMobil’s notice to us of the completion of the expansion of certain CO2 delivery facilities by ExxonMobil and that it is prepared to deliver the required daily quantity as required under the agreement. Either party may extend the agreement for an additional ten year term following proper notice and agreement to certain applicable terms of the agreement. Following the commencement of the primary term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of CO2 per day. We have agreed to a “take-or-pay” provision under the agreement. For CO2 deliveries from ExxonMobil, we have agreed to pay a base price plus an Oil Price Factor which is indexed to the price of West Texas Intermediate crude oil.

We may terminate the agreement if ExxonMobil fails to meet the Company’s quantity nomination of CO2 (not to exceed 70 MMscfd per day) for 30 consecutive days except under certain circumstances. Either party has the right to terminate the agreement at any time with notice to the other party based on certain circumstances described in the agreement. ExxonMobil is not obligated to commence delivery of CO2 until we provide a surety bond equal to four months’ supply of CO2. ExxonMobil may also request additional financial performance assurances if it has reasonable grounds for believing that we have ceased to have the financial resources to meet our obligations under the agreement and ExxonMobil may suspend delivery of CO2 until the appropriate assurances are provided. ExxonMobil may terminate the agreement if a requested performance assurance is not provided by us within 30 days of a request.

Under the terms of the agreement, ExxonMobil is responsible for paying all taxes and royalties up to the delivery point except that we are obligated to reimburse ExxonMobil for 100% of any new, increased, or additional taxes or royalties incurred up to the delivery point. The CO2 is to be supplied from ExxonMobil’s LaBarge gas field in Wyoming.

Initially, the source of funds to fulfill our commitment to purchase CO2 from Anadarko and ExxonMobil will be either the long term debt financing or our strategic partner. As crude oil production from the fields into which CO2 is injected increases, we anticipate utilizing a portion of the proceeds from the sale of such crude oil to pay for the CO2.

On April 3, 2009, we were informed by ExxonMobil that it was terminating the Agreement based on our failure to provide performance assurances in the form of a letter of credit. We believe that the Agreement does not obligate us to provide any performance assurances until the start-up of CO2 delivery, which will not occur in 2009. Accordingly, we disagree with ExxonMobil’s rationale for purportedly terminating the Agreement and believes in good faith that ExxonMobil’s termination of the Agreement has not occurred pursuant to the terms of the Agreement and is unlawful. We have notified ExxonMobil of our position.

Results of Operations

Rancher Energy Corp.

Results of Operations

Years Ended March 31,

	2009			2008
Revenue:
Oil production (in barrels)		65,308			86,626
Oil price (per barrel)	$	78.71		$	73.24
Oil and gas sales	$	5,140,660		$	6,344,414
Derivative gains (losses)		1,020,672			(956,142	)
		6,161,332			5,388,272

Operating expenses:
Production taxes		647,755			772,010
Lease operating expenses		2,423,015			2,906,210
Depreciation, depletion, and amortization		1,196,970			1,360,737
Impairment of unproved properties		39,050,000
Accretion expense		158,009			121,740
Exploration expense		20,108			223,564
General and administrative		3,631,581			7,538,242
Total operating expenses		47,127,438			12,922,503
Loss from operations		(40,966,105	)		(7,534,231	)

Other income (expense):
Liquidated damages pursuant to registration rights agreement		-			(2,645,393	)
Interest expense		(1,369,957	)		(794,693	)
Amortization of deferred financing costs		(4,021,767			(2,423,389	)
Interest and other income		16,489			232,880
Total other income (expense)		(5,375,235	)		(5,630,595	)
Net loss	$	(46,341,341	)	$	(13,164,826	)

Year Ended March 31, 2009 Compared to Year Ended March 31, 2008

Overview. For the year ended March 31, 2009, we reflected a net loss of $46,341,341, or $0.40 per basic and fully diluted share, as compared to a loss of $13,164,826, or $0.12 per basic and fully diluted share, for the corresponding year ended March 31, 2008.

Revenue, production taxes, and lease operating expenses. For the year ended March 31, 2009, we recorded crude oil sales of $5,140,660 on 65,308 barrels of oil at an average price of $78.71, as compared to revenues of $6,344,414 on 86,626 barrels of oil at an average price of $73.24 per barrel in 2008. The year-to-year variance reflects a volume variance of $(1,561,312) and a price variance of $357,558. The decreased volume of crude oil sold in 2009 as compared to 2008 primarily reflects mechanical problems encountered on producing wells and facilities resulting in periodic production downtime on numerous wells, coupled natural decline in these mature fields. Production taxes (including ad valorem taxes) of $647,755 in 2009 as compared to $772,010 in 2008, remained constant at 12% of crude oil sales revenues. Lease operating expenses decreased in absolute dollar amounts to $2,423,015 in 2009 as compared to $2,906,210 in 2008; however operating costs per barrel increased to $37.10 per barrel in 2009 compared to $33.55 per barrel in 2008. The per barrel increase in primarily reflects the costs associated with the repair and maintenance work carried out on wells and facilities in our effort to maintain and increase production levels.

Derivative gains (losses). In connection with short term debt financing entered into in October 2007 we entered into a crude oil derivative contract with an unrelated counterparty to set a price floor of $65 per barrel for 75% of our estimated crude oil production for the next two years, and a price ceiling of $83.50 for 45% of the same level of production. During the year ended March 31, 2009 we recorded total gains on the derivative activities of $1,020,672 comprised of $206,895 of realized losses and $1,227,567 of unrealized gains of reflecting the reversal of previously recorded unrealized losses. For the comparable 2008 periods we recorded derivative losses of $956,142 comprised of realized losses of $184,535 and unrealized losses of $771,607

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased (DD&A) to $1,196,970 in 2009 as compared to $1,360,737 in 2008. In 2009 DD&A is comprised of $1,009,359 of DD&A of oil and gas properties ($15.45/ bbl) and depreciation of furniture and fixtures of $187,610. Corresponding amounts for 2008 were $1,183,798 of DD&A of oil and gas properties ($13.66/ bbl) and depreciation of furniture and fixtures of $176,939. The per barrel increase in 2009 reflects lower crude oil reserve volumes in 2009 as compared to 2008.

Impairment of unproved properties. In conjunction with the periodic assessment of impairment of unproved properties, we-evaluated the carrying value of our unproved properties giving consideration to lower crude oil prices and the difficulties encountered in securing capital to develop the properties. Accordingly, during the year ended March 31, 20098 we recorded $39,050,000 of impairment expense of unproved properties, reflecting the excess of the carrying value over estimated realizable value of the assets. No such impairment of unproved properties was recorded for the year ended March 31, 2008. .

Exploration expense. For the year ended March 31, 2009, we reflected exploration expense. of $20,108 compared to of $223,564 in 2008. The decrease reflects reduced emphasis on preparation for seismic work in the 2009 period.

General and administrative expense. For the year ended March 31, 2009 we reflected general and administrative expenses of $3,631,581 as compared to $7,538,242 for the corresponding year ended March 31, 2008. Significant components of the 2008-2009 year-to-year variance include:

Salaries and benefits - decrease of $1,984,000 reflecting staff reductions carried out in the March-August 2008 time period. Overall staff count was reduced from 24 in March 2008 to 7 in March 2009;

Share based payments – decrease of $680,000 reflecting expenses associated with qualified stock options forfeited by terminated employees;

Consultants and contractors – decrease of $795,000 including:

- accounting and financial reporting consulting - decrease of $409,000 compared to 2008 expenses which included costs associated with completion of our S-1 registration statement, not incurred in FY 2009;

-consulting fees for recruiting services - decrease of $297,000 compared to 2008 expenses which included costs associated with selection of Board Members and certain other staff – no such expenses incurred in FY 2009;

-IT related consulting - decrease of $88,000, -reflecting significantly lower levels of activity and staff count FY 2009 as compared to FY 2008;

Office rent – increase of $85,000 reflecting full year effect of larger office space commencing mid-year FY 2008

Audit and professional accounting fees – decrease of $359,000 - FY 2008 amount included costs associated with the audit of the Company’s internal control over financial reporting; costs associated with review of our S-1 registration statement and the costs associated with predecessor and pre-predecessor audits. FY 2009 expense include only routine audit and tax prep fees;

.Investor relations – decrease of $74,000 – lower level of activity and termination of investor relations consultant in FY 2009;

Travel and Entertainment- decrease of $99,000 reflecting lower level of activity and lower staff count in FY 2009.

Liquidated damages pursuant to registration rights agreement. Our Registration Statement on Form S-1 was declared effective by the SEC on October 31, 2007 and has been maintained effective since that date. Accordingly, we recorded no liquidated damages pursuant to the registration rights arrangement in the year ended March 31, 2009, as compared to $2,645,393 in the comparable period in 2008.

Amortization of deferred financing costs. For the year ended March 31, 2009, we reflected amortization of deferred financing costs of $4,021,767 as compared to $2,423,389 for the corresponding year ended March 31, 2008. The amounts include amortization of deferred finance costs and amortization of the discount on the note payable related to the issuance of short term debt in October 2007. The year-to-year increase reflects a full year of such costs in 2009 as compared to only 5 months in 2008.).

Interest expense. For the year ended March 31, 2009 we reflected interest expense of $1,369,957 as compared to $794,693 reflected in the comparable period of 2008, reflecting the full year effect of the outstanding debt in2009 compared to only six months in 2008.

Interest income. For the year ended March 31, 2009, we reflected interest income of $16,489 as compared to $232,880 for the corresponding year ended March 31, 2008 reflecting lower interest earning cash balances in 2009 as compared to 2008.

Liquidity and Capital Resources

Our current cash reserves are sufficient to continue operations through the end of September 2009. Our short-term debt is due in October 2009. If we are not successful in raising substantial funding or closing a strategic partnering transaction to address our cash needs and our short-term debt within the required timeframe, we may need to cease operations.

Going Concern

The report of our independent registered public accounting firm on the financial statements for the year ended March 31, 2009 and 2008 includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. We have incurred a cumulative net loss of $68.7 million for the period from inception (February 4, 2004) to March 31, 2009. As of March 31, 2009 we had cash on hand of $0.9 million, short term debt of $10 million and we have a working capital deficit of approximately $8.8 million. The short term debt which had a scheduled maturity date of April 30, 2009, has been extended to October 15, 2009. We require significant additional funding to repay the short term debt and sustain our current operations. Our ability to continue the Company as a going concern is dependent upon our ability to obtain additional funding in order to pay our short term debt and finance our planned operations.

Our primary source of liquidity to meet operating expenses and fund capital expenditures is our access to debt and equity markets. The debt and equity markets, public, private, and institutional, have been our principal source of capital used to finance a significant amount of growth, including property acquisitions. We will need substantial additional funding to continue operations and to pursue our business plan. The recent unprecedented events in global financial markets have had a profound impact on the global economy. Many industries, including the oil and natural gas industry, are impacted by these market conditions. Some of the key impacts of the current financial market turmoil include contraction in credit markets resulting in a widening of credit risk, devaluations and high volatility in global equity, commodity, natural resources and foreign exchange markets, and a lack of market liquidity. A continued or worsened slowdown in the financial markets or other economic conditions, including but not limited to, employment rates, business conditions, lack of available credit, the state of the financial markets and interest rates may adversely affect our opportunities.

In October 2007, we issued $12,240,000 of short term debt the proceeds of which were intended to enhance our existing production and to provide cash reserves for operations. The debt was scheduled to mature on October 31, 2008. We had planned to secure longer term fixed rate financing to repay the short term debt and to commence our EOR development activities in the three fields of the Powder River Basin; however, due to difficulties in the capital debt markets, we have been unable to secure such financing. On October 22, 2008 we and the lender entered into an amendment to the credit agreement to, among other terms, extend the maturity date by six months, until April 30, 2009. In consideration for the extension and other terms, we made a principal payment of $2,240,000 reducing the outstanding balance to $10,000,000. Subsequent the end of our fiscal year we and the lender entered into a series amendments to the credit agreement ultimately extending the maturity date to October 15, 2009. We do not have cash available to repay this loan. If we are not successful in repaying this debt within the term of the loan, or default under the terms of the loan, the lender will be able to foreclose one or more of our three properties and other assets and we could lose the properties. A foreclosure could significantly reduce or eliminate our property interests or force us to alter our business strategy, which could involve the sale of properties or working interests in the properties. A foreclosure would adversely affect our results of operations and financial condition including a possible termination of business activities.

Beginning in March 2008, we reduced our level of staffing by laying off several employees whose positions were considered to be redundant based upon the anticipated closing of a farmout transaction with experienced industry operators. Neither the original nor a subsequently identified farmout transaction was completed; however we continued field and corporate operations utilizing the remaining staff and, on a very limited contract basis, the utilization of contract consultants. At that time our monthly oil and gas production revenue was adequate to cover monthly field operating costs, production taxes and general and administrative expenses; however, interest payments on short term debt and payments relating to our crude oil hedging position resulted in negative cash flow each month. The collapse of crude oil prices commencing in August 2008 and continuing to date has exacerbated the situation, such that at current NYMEX strip prices our expected future cash flows from crude oil sale are inadequate to cover monthly field operating costs, production taxes and general and administrative expenses. This negative cash flow is offset to some extent by proceeds realized from our crude oil hedging position. This hedge expires in October 2009. Our current cash reserves are not adequate to fund our operations for the next fiscal year.

We have executed two agreements to purchase CO2 for use in EOR operations in our fields. Each contract contains provisions for a take or pay obligation for the purchase of CO2. As discussed in Item 1. BUSINESS, ExxonMobil has given us notice of termination of their supply agreement. We disagree with their position and have notified them of our disagreement. As of the date of this Annual Report, we are currently in discussions with Anadarko to amend the Purchase Contract to minimize or eliminate certain uncertain provisions and terms of the agreement that are subject to differing interpretations. There is no assurance we will successfully complete any such amendment and in the event we do not, we will likely be unable to sustain operations or meet our obligations under the supply agreement

In 2008, we retained a financial advisor to consider financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to continue operations will be dependent upon completing a strategic transaction; however, there is no assurance that any transaction will be completed.

Change in Financial Condition

In October 2007 we issued short term debt in the amount of $12.24 million the proceeds of which were intended to enhance our existing production and to provide cash reserves for operations. In October 2008, we repaid $2.24 million of the outstanding balance and we and the lender amended the credit agreement to, among other things, extend the maturity date to April 30, 2009. Subsequent to the end of our fiscal year, March 31, 2009, we and the lender amended the credit agreement to further extend the maturity date to October 15, 2009. The debt bears interest at 16% per annum and is secured by all of our assets.

Cash Flows

The following is a summary of Rancher Energy’s comparative cash flows:

	For the Year Ended March 31,
	2009			2008
Cash flows from (used for)::
Operating activities	$	(2,964,942	)	$	(4,586,423	)
Investing activities	$	(618,791	)	$	(4,681,280	)
Financing activities	$	(2,341,470	)	$	10,980,185

Analysis of cash flow changes between 2009 and 2008

Cash flows used for operating activities decreased as a result of lower general and administrative expenses as discussed above, partially offset by payments to settle derivative activity losses and interest expense incurred in connection with the October 2007 short term financing.

Cash flows used for investing activities decreased in the 2009 period compared to the 2008 period as we expended significantly less on oil and gas properties, $260,000 in 2009 compared to $4,245,000 in 2008. In response to our lack of success in securing additional financing during the period, we have curtailed capital spending to the minimum required to maintain current levels of crude oil production.

Cash flows used for financing activities in 2009 includes the repayment of a portion of the debt incurred in 2007 ($2,240,000) and financing costs incurred to complete requirements of the short term debt agreement. The source of cash in 2007 represents the proceeds for the short term debt, net of offering and finance costs.

Capital Expenditures

The following table sets forth certain historical information regarding costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed.

	For the Years Ended March 31,
	2009		2008

Exploration	$	20,108	$	223,564
Development	$	245,102	$	4,758,783
Acquisitions:
Unproved	$	-	$	43,088
Proved	$	-	$	-
Total		265,280		5,025,435

Capitalized costs associates with asset retirement obligations.	$	10,481	$	213,756

Off-Balance Sheet Arrangements

Under the terms of the Term Credit Agreement entered into in October 2007 we were required hedge a portion of our expected production and we entered into a costless collar agreement for a portion of our anticipated future crude oil production. The costless collar contains a fixed floor price (put) and ceiling price (call). If the index price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. During the year ended March 31, 2009 we reflected realized losses of $206,895 and unrealized gains of $1,227,567 from the hedging activity, as compared to realized losses of $184,535 and unrealized losses of $771,607 for the comparable 2008 period.

We have no other off-balance sheet financing nor do we have any unconsolidated subsidiaries.

Critical Accounting Policies and Estimates

We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil. Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions, which affect the estimates we use, on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changing business conditions or unexpected circumstances. Policies we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies see Note 1—Organization and Summary of Significant Accounting Policies, Note 3—Asset Retirement Obligations, and Note 10—Disclosures About Oil and Gas Producing Activities to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2009 in Part IV, Item 15, of this Annual Report.

Oil and Gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash flows are the most important estimates for an exploration and production company because they affect our perceived value, are used in comparative financial analysis ratios and are used as the basis for the most significant accounting estimates in our financial statements. This includes the periodic calculations of depletion, depreciation, and impairment for our proved oil and gas assets. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in effect at the end of each period to the estimated quantities of oil and gas remaining to be produced as of the end of that period. Expected cash flows are reduced to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation required by SFAS No.69, Disclosures About Oil and Gas Producing Activities, requires a 10% discount rate to be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, which are prepared by independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available or as oil and gas prices and operating and capital costs change. We evaluate and estimate our oil and gas reserves at March 31 of each year. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions. Changes in depletion, depreciation, or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period that the reserve estimates change.

Successful efforts method of accounting. Generally accepted accounting principles provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities and a detailed description is included in Note 1– Organization and Summary of Significant Accounting Policies to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2009 in Part IV, Item 15, of this Annual Report.

Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced crude oil. We report revenue as the gross amounts we receive for our net revenue interest before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, , NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.

Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of Federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates and determine what credit adjusted risk-free rate to use. The statement of operations impact of these estimates is reflected in our depreciation, depletion, and amortization and accretion calculations and occurs over the remaining life of our oil and gas properties.

Valuation of long-lived and intangible assets. Our property and equipment is recorded at cost. An impairment allowance is provided on unproved property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the realizability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenues from a property, using escalated pricing, with the related net capitalized costs of the property at the end of each period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is written down to our estimate of fair value, which is determined by applying a discount rate that we believe is indicative of the current market. Our criteria for an acceptable internal rate of return are subject to change over time. Different pricing assumptions or discount rates could result in a different calculated impairment.

Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFASNo.109, Accounting for Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our Federal and state income tax returns are generally not filed before the financial statements are prepared, therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we used and actual amounts we reported are recorded in the period in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery could have an impact on our results of operations. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. To date, we have not recorded any deferred tax assets because of the historical losses that we have incurred.

Stock-based compensation. As of April 1, 2006, we adopted the provisions of SFAS No.123(R). This statement requires us to record expense associated with the fair value of stock-based compensation.

Commodity Derivatives. The Company accounts for derivative instruments or hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities”. SFASNo.133 requires the Company to record derivative instruments at their fair value. The Company’s risk management strategy is to enter into commodity derivatives that set “price floors” and “price ceilings” for its crude oil production. The objective is to reduce the Company’s exposure to commodity price risk associated with expected crude oil production.

The Company has elected not to designate the commodity derivatives to which they are a party as cash flow hedges, and accordingly, such contracts are recorded at fair value on its consolidated balance sheets and changes in such fair value are recognized in current earnings as income or expense as they occur.

As of March 31, 2009, we had a net derivative asset of $455,960 which was measured based upon our valuation model and, as such, is classified as a Level 3 fair value measurement. We value these Level 3 contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors (d) notional quantities (e) current market and contractual prices for the underlying instruments and (f) the counterparty’s and the Company’s credit ratings. The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations. Continued volatility in these markets could have a significant impact on the fair value of our derivative contracts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. With increases to our production, exposure to this risk will become more significant. We expect commodity price volatility to continue. Under the terms of our Term Credit Agreement we entered into in October 2007, we were required hedge a portion of our expected future production.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements and Supplementary Data required by this Item 8 are set forth following the signature page and exhibit index of this Annual Report and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

Controls and Procedures.

We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. We identified a material weakness in our internal control over financial reporting and, as a result of this material weakness, we concluded as of March 31, 2009 that our disclosure controls and procedures were not effective.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) is defined as a process designed by, or under the supervision of, a company’s principal executive and financial officers, or persons performing similar functions, and effected by a company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally acceptable accounting principles and includes those policies and procedures that:

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

A material weakness is a control deficiency, or combination of control deficiencies, that result in more than a remote likelihood that a material misstatement of annual or interim financial statements will not be prevented or detected. As of March 31, 2009, the Company identified the following material weakness:

We did not adequately segregate the duties of different personnel within our Accounting Department due to an insufficient complement of staff and inadequate management oversight.

We have limited accounting personnel with sufficient expertise in generally accepted accounting principles to enable effective segregation of duties with respect to recording journal entries and to allow for appropriate monitoring of financial reporting matters and internal control over financial reporting. Specifically, the Chief Accounting Officer has involvement in the creation and review of journal entries and note disclosures without adequate independent review and authorization. This control deficiency is pervasive in nature and impacts all significant accounts. This control deficiency also affects the financial reporting process including financial statement preparation and the related note disclosures.

As a result of the aforementioned material weakness, management concluded that the Company’s internal control over financial reporting as of March 31, 2009 was not effective.

Management’s Planned Corrective Actions

In relation to the material weakness identified above, and subject to obtaining permanent financing, our management and the board of directors intend to work to remediate the risk of a material misstatement in financial reporting. Subject to obtaining permanent financing, we intend to implement the following plan to address the risk of a material misstatement in the financial statements:

Engage qualified accounting staff to prepare journal entries and note disclosures thereby enabling our Chief Accounting Officer the opportunity to independently review and authorize such entries and disclosures prior to entering the information into the accounts and financial statement disclosures,

Engage qualified third-party accountants and consultants to assist us in the preparation and review of our financial information,

Ensure employees, third-party accountants and consultants who are performing controls understand responsibilities and how to perform said responsibilities, and

Consult with qualified third-party accountants and consultants on the appropriate application of generally accepted accounting principles for complex and non-routine transactions.

Auditors Attestation

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required by this Item with respect to the Company’s directors, executive officers, certain family relationships, and compliance by the Company’s directors, executive officers and certain beneficial owners of the Company’s common stock with Section 16(a) of the Exchange Act is incorporated by reference to all information under the captions entitled “Directors, Officers and Corporate Governance” and “Compliance with Section 16(a) of the Securities Act of 1934” from our Proxy Statement relating to our 2009 Annual Meeting of Stockholders. (“Proxy Statement”) that is expected to be filed in July 2009.

The information regarding our Audit Committee, including our audit committee financial expert and our director nomination process, is incorporated herein by reference to all information under the caption entitled “Audit Committee” included in our Proxy Statement.

We have adopted a Code of Business Conduct and Ethics for Directors, Officers, and Employees. We undertake to provide any person, without charge, a copy of the Code of Business Conduct and Ethics. Requests should be submitted in writing to the attention of our Chief Accounting Officer, Rancher Energy Corp., 999-18th Street, Suite 3400, Denver, Colorado 80202.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is hereby incorporated herein by reference to the information under the caption “Executive Compensation” included in the Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12, as to certain beneficial owners and management, is hereby incorporated herein by reference to the information under the caption “Security Ownership of Directors and Executive Officers” included in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by Item 13 is hereby incorporated herein by reference to the information under the caption “Certain Relationships and Related Transactions” and “Director Independence” included in the Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is hereby incorporated herein by reference to the information under “Proposal #2 - Ratification of the Appointment of Independent Registered Accountant” included in the Proxy Statement.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as a part of the report:

(1)

Index to Consolidated Financial Statements of the Company

An “Index to Consolidated Financial Statements” has been filed as a part of this Report beginning on page F-1 hereof.

(2)

All schedules for which provision is made in the applicable accounting regulation of the SEC have been omitted because of the absence of the conditions under which they would be required or because the information required is included in the consolidated financial statements of the Registrant or the notes thereto.

(3)

Exhibits

Exhibit		Description
3.1		Amended and Restated Articles of Incorporation (1)
3.2		Articles of Correction (2)
3.3		Amended and Restated Bylaws (3)
4.1		Form of Stock Certificate for Fully Paid, Non-Assessable Common Stock of the Company (4)
4.2		Form of Registration Rights Agreement, dated December 21, 2006 (5)
4.3		Form of Warrant to Purchase Common Stock (5)

10.1		Employment Agreement between John Works and Rancher Energy Corp., dated June 1, 2006 (6)
10.2		Assignment Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp., dated June 6, 2006 (6)
10.3		Loan Agreement between Enerex Capital Corp. and Rancher Energy Corp., dated June 6, 2006 (6)
10.4		Letter Agreement between NITEC LLC and Rancher Energy Corp., dated June 7, 2006 (6)
10.5		Loan Agreement between Venture Capital First LLC and Rancher Energy Corp., dated June 9, 2006 (7)
10.6		Exploration and Development Agreement between Big Snowy Resources, LP and Rancher Energy Corp., dated June 15, 2006 (6)
10.7		Assignment Agreement between PIN Petroleum Ltd. And Rancher Energy Corp., dated June 6, 2006.(6)
10.8		Rancher Energy Corp. 2006 Stock Incentive Plan (8)
10.9		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement (8)
10.10		Denver Place Office Lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated October 30, 2006 (9)
10.11		Amendment to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp. (10)
10.12		Product Sale and Purchase Agreement by and between Rancher Energy Corp. and the Anadarko Petroleum Corporation, dated December 15, 2006(11)
10.13		Voting Agreement between Rancher Energy Corp. and Stockholders identified therein, dated as of December 13, 2006 (5)
10.14		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement (12)
10.15		First Amendment to Employment Agreement by and between John Works and Rancher Energy Corp., dated March 14, 2007 (13)
10.16		Employment Agreement between Richard Kurtenbach and Rancher Energy Corp., dated August 3, 2007(14)
10.17		Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)
10.18		Term Note made by Rancher Energy Corp. in favor of GasRock Capital LLC, dated October 16, 2007 (15)
10.19		Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated as of October 16, 2007 (16)
10.20		Security Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)
10.21		Conveyance of Overriding Royalty Interest by Rancher Energy Corp. in favor of GasRock Capital LLC, dated as of October 16, 2007 (15)
10.22		ISDA Master Agreement between Rancher Energy Corp. and BP Corporation North America Inc., dated as of October 16, 2007 (15)
10.23		Restricted Account and Securities Account Control Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National Association, dated as of October 16, 2007 (15)
10.24		Intercreditor Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and BP Corporation North America Inc., dated as of October 16, 2007 (15)
10.25		First Amendment to Denver Place Office lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated March 6, 2007 (13)
10.26		Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated effective as of February 1, 2008 (Certain portions of this agreement have been redacted and have been filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Request). (16)
10.27		Stay Bonus Agreements between Rancher Energy Corp. and John Works and Richard E. Kurtenbach and all of the Company’s employees, dated October 2, 2008.(17)
10.28		First Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated October 22, 2008.(18)
10.29		Assignment Agreement between Rancher Energy Corp. and Merit Energy Company, LLC, dated March 18,2009.(19)
10.30		Termination of Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated April 3, 2009.(20)
10.31		Second Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated April 30, 2009.(21)
10.32		Third Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 8, 2009.(22)
10.33		Fourth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 13, 2009.(23)
10.34		Fifth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 19, 2009.(24)
10.35		Sixth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 21, 2009.(25)
10.36		Seventh Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 27 2009.(26)
10.37		Eighth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated June 3, 2009.(27)
23.1		Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers*
31.1		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)*
31.2		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)*
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

* Filed herewith.

(1)	Incorporated by reference from our Current Report on Form 8-K filed on April 3, 2007.

(2)	Incorporated by reference from our Form 10-Q for the quarterly period ended September 30, 2007.

(3)	Incorporated by reference from our Current Report on Form 8-K filed on December 18, 2006.

(4)	Incorporated by reference from our Form SB-2 Registration Statement filed on June 9, 2004.

(5)	Incorporated by reference from our Current Report on Form 8-K filed on December 27, 2006.

(6)	Incorporated by reference from our Annual Report on Form 10-K filed on June 30, 2006.

(7)	Incorporated by reference from our Current Report on Form 8-K filed on June 21, 2006.

(8)	Incorporated by reference from our Current Report on Form 8-K filed on October 6, 2006.

(9)	Incorporated by reference from our Current Report on Form 8-K filed on November 9, 2006.

(10)	Incorporated by reference from our Current Report on Form 8-K filed on December 4, 2006.

(11)	Incorporated by reference from our Current Report on Form 8-K filed on December 22, 2006.

(12)	Incorporated by reference from our Annual Report on Form 10-K filed on June 29, 2007.

(13)	Incorporated by reference from our Current Report on Form 8-K filed on March 20, 2007.

(14)	Incorporated by reference from our Current Report on Form 8-K filed on August 7, 2007.

(15)	Incorporated by reference from our Current Report on Form 8-K filed on October 17, 2007.

(16)	Incorporated by reference from our Current Report on Form 8-K filed on February 14, 2008.

(17)	Incorporated by reference from our Current Report on Form 8-K filed on October 3, 2008.

(18)	Incorporated by reference from our Current Report on Form 8-K filed on October 23, 2008.

(19)	Incorporated by reference from our Current Report on Form 8-K filed on March 24, 2009.

(20)	Incorporated by reference from our Current Report on Form 8-K filed on April 9, 2009.

(21)	Incorporated by reference from our Current Report on Form 8-K filed on April 30, 2009.

(22)	Incorporated by reference from our Current Report on Form 8-K filed on May 11, 2009.

(23)	Incorporated by reference from our Current Report on Form 8-K filed on May 14, 2009.

(24)	Incorporated by reference from our Current Report on Form 8-K filed on May 20, 2009.

(25)	Incorporated by reference from our Current Report on Form 8-K filed on May 22, 2009.

(26)	Incorporated by reference from our Current Report on Form 8-K filed on May 28, 2009.

(27)	Incorporated by reference from our Current Report on Form 8-K filed on June 5, 2009.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, this 14th day of July, 2009.

RANCHER ENERGY CORP.

/s/ John Works

John Works, President, Chief Executive Officer,

Principal Executive Officer, Chief Financial Officer,

Principal Financial Officer, Director, Secretary,

and Treasurer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ John Works	President, Chief Executive Officer,	7/14/2009
John Works	Principal Executive Officer, Chief Financial Officer, Principal Financial Officer, Director, Secretary, and Treasurer

/s/Richard Kurtenbach
Richard E. Kurtenbach	Chief Accounting Officer and Principal Accounting Officer	7/14/2009

/s/ William A. Anderson
William A. Anderson	Director	7/14/2009

/s/ Joseph P. McCoy
Joseph P. McCoy	Director	7/14/2009

/s/ Patrick M. Murray
Patrick M. Murray	Director	7/14/2009

/s/ Myron M. Sheinfeld
Myron M. Sheinfeld	Director	7/14/2009

/s/ Mark Worthey
Mark Worthey	Director	7/14/2009

EXHIBIT INDEX

Exhibit		Description
3.1		Amended and Restated Articles of Incorporation (1)
3.2		Articles of Correction (2)
3.3		Amended and Restated Bylaws (3)
4.1		Form of Stock Certificate for Fully Paid, Non-Assessable Common Stock of the Company (4)
4.2		Form of Registration Rights Agreement, dated December 21, 2006 (5)
4.3		Form of Warrant to Purchase Common Stock (5)
10.1		Employment Agreement between John Works and Rancher Energy Corp., dated June 1, 2006 (6)
10.2		Assignment Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp., dated June 6, 2006 (6)
10.3		Loan Agreement between Enerex Capital Corp. and Rancher Energy Corp., dated June 6, 2006 (6)
10.4		Letter Agreement between NITEC LLC and Rancher Energy Corp., dated June 7, 2006 (6)
10.5		Loan Agreement between Venture Capital First LLC and Rancher Energy Corp., dated June 9, 2006 (7)
10.6		Exploration and Development Agreement between Big Snowy Resources, LP and Rancher Energy Corp., dated June 15, 2006 (6)
10.7		Assignment Agreement between PIN Petroleum Ltd. And Rancher Energy Corp., dated June 6, 2006.(6)
10.8		Rancher Energy Corp. 2006 Stock Incentive Plan (8)
10.9		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement (8)
10.10		Denver Place Office Lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated October 30, 2006 (9)
10.11		Amendment to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp. (10)
10.12		Product Sale and Purchase Agreement by and between Rancher Energy Corp. and the Anadarko Petroleum Corporation, dated December 15, 2006(11)
10.13		Voting Agreement between Rancher Energy Corp. and Stockholders identified therein, dated as of December 13, 2006 (5)
10.14		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement (12)
10.15		First Amendment to Employment Agreement by and between John Works and Rancher Energy Corp., dated March 14, 2007 (13)
10.16		Employment Agreement between Richard Kurtenbach and Rancher Energy Corp., dated August 3, 2007(14)
10.17		Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)
10.18		Term Note made by Rancher Energy Corp. in favor of GasRock Capital LLC, dated October 16, 2007 (15)
10.19		Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated as of October 16, 2007 (16)
10.20		Security Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)
10.21		Conveyance of Overriding Royalty Interest by Rancher Energy Corp. in favor of GasRock Capital LLC, dated as of October 16, 2007 (15)
10.22		ISDA Master Agreement between Rancher Energy Corp. and BP Corporation North America Inc., dated as of October 16, 2007 (15)
10.23		Restricted Account and Securities Account Control Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National Association, dated as of October 16, 2007 (15)
10.24		Intercreditor Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and BP Corporation North America Inc., dated as of October 16, 2007 (15)
10.25		First Amendment to Denver Place Office lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated March 6, 2007 (13)
10.26		Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated effective as of February 1, 2008 (Certain portions of this agreement have been redacted and have been filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Request). (16)

10.27		Stay Bonus Agreements between Rancher Energy Corp. and John Works and Richard E. Kurtenbach and all of the Company’s employees, dated October 2, 2008.(17)
10.28		First Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated October 22, 2008.(18)
10.29		Assignment Agreement between Rancher Energy Corp. and Merit Energy Company, LLC, dated March 18,2009.(19)
10.30		Termination of Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated April 3, 2009.(20)
10.31		Second Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated April 30, 2009.(21)
10.32		Third Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 8, 2009.(22)
10.33		Fourth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 13, 2009.(23)
10.34		Fifth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 19, 2009.(24)
10.35		Sixth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 21, 2009.(25)
10.36		Seventh Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 27 2009.(26)
10.37		Eighth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated June 3, 2009.(27)
23.1		Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers*
31.1		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)*
31.2		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)*
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

* Filed herewith.

(1)	Incorporated by reference from our Current Report on Form 8-K filed on April 3, 2007.

(2)	Incorporated by reference from our Form 10-Q for the quarterly period ended September 30, 2007.

(3)	Incorporated by reference from our Current Report on Form 8-K filed on December 18, 2006.

(4)	Incorporated by reference from our Form SB-2 Registration Statement filed on June 9, 2004.

(5)	Incorporated by reference from our Current Report on Form 8-K filed on December 27, 2006.

(6)	Incorporated by reference from our Annual Report on Form 10-K filed on June 30, 2006.

(7)	Incorporated by reference from our Current Report on Form 8-K filed on June 21, 2006.

(8)	Incorporated by reference from our Current Report on Form 8-K filed on October 6, 2006.

(9)	Incorporated by reference from our Current Report on Form 8-K filed on November 9, 2006.

(10)	Incorporated by reference from our Current Report on Form 8-K filed on December 4, 2006.

(11)	Incorporated by reference from our Current Report on Form 8-K filed on December 22, 2006.

(12)	Incorporated by reference from our Annual Report on Form 10-K filed on June 29, 2007.

(13)	Incorporated by reference from our Current Report on Form 8-K filed on March 20, 2007.

(14)	Incorporated by reference from our Current Report on Form 8-K filed on August 7, 2007.

(15)	Incorporated by reference from our Current Report on Form 8-K filed on October 17, 2007.

(16)	Incorporated by reference from our Current Report on Form 8-K filed on February 14, 2008.

(17)	Incorporated by reference from our Current Report on Form 8-K filed on October 3, 2008.

(18)	Incorporated by reference from our Current Report on Form 8-K filed on October 23, 2008.

(19)	Incorporated by reference from our Current Report on Form 8-K filed on March 24, 2009.

(20)	Incorporated by reference from our Current Report on Form 8-K filed on April 9, 2009.

(21)	Incorporated by reference from our Current Report on Form 8-K filed on April 30, 2009.

(22)	Incorporated by reference from our Current Report on Form 8-K filed on May 11, 2009.

(23)	Incorporated by reference from our Current Report on Form 8-K filed on May 14, 2009.

(24)	Incorporated by reference from our Current Report on Form 8-K filed on May 20, 2009.

(25)	Incorporated by reference from our Current Report on Form 8-K filed on May 22, 2009.

(26)	Incorporated by reference from our Current Report on Form 8-K filed on May 28, 2009.

(27)	Incorporated by reference from our Current Report on Form 8-K filed on June 5, 2009.

INDEX TO FINANCIAL STATEMENTS

Audited Financial Statements - Rancher Energy Corp.

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets as of March 31, 2009 and 2008	F-3

Statements of Operations for the Years Ended March 31, 2009 and 2008	F-4

Statement of Changes in Stockholders’ Equity (Deficit) for the Years Ended March 31, 2009 and 2008	F-5

Statements of Cash Flows for the Years Ended March 31, 2009 and 2008	F-6

Notes to Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Rancher Energy Corp.

We have audited the accompanying balance sheets of Rancher Energy Corp. (the “Company”) as of March 31, 2009 and 2008, and the related statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rancher Energy Corp. as of March 31, 2009 and 2008, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2009, in conformity with U.S. generally accepted accounting principles.

We were not engaged to examine management’s assessment of the effectiveness of Rancher Energy Corp.’s internal control over financial reporting as of March 31, 2009, included in the accompanying Management Report on Internal Controls and, accordingly, we do not express an opinion thereon.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations and has a working capital deficit and will require significant additional funding to repay its short-term debt and for planned oil and gas development operations. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

HEIN & ASSOCIATES LLP

Denver, Colorado

July 13, 2009

F-2

Rancher Energy Corp.

Balance Sheets

	March 31,
	2009			2008
ASSETS

Current assets:
Cash and cash equivalents	$	917,160		$	6,842,365
Accounts receivable and prepaid expenses		584,139			1,170,641
Derivative receivable		455,960			-
Total current assets		1,957,259			8,013,006

Oil and gas properties (successful efforts method):
Unproved		53,328,147			54,058,073
Proved		20,631,487			20,734,143
Less: Accumulated depletion, depreciation, amortization and impairment		(41,840,978	)		(1,531,619	)
Net oil and gas properties		32,118,656			73,260,597

Furniture and equipment, net of accumulated depreciation of $381,396 and $204,420, respectively		770,354			997,196
Other assets		933,592			1,300,382
Total other assets		1,703,946			2,297,578
Total assets	$	35,779,861		$	83,571,181

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	816,808		$	2,114,204
Accrued oil and gas property costs		-			250,000
Asset retirement obligation		108,884			337,685
Derivative liability		-			590,480
Note payable, net of unamortized discount of $165,790 and $2,527,550, respectively		9,834,210			9,712,450
Total current liabilities		10,759,902			13,004,819

Long-term liabilities:
Derivative liability		-			246.553
Asset retirement obligation		1,171,796			922,166
Total long-term liabilities		1,171,796			1,168,719

Commitments and contingencies (Note 6)

Stockholders’ equity:
Common stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized at March 31, 2009 and 2008 ; 119,016,700 and 114,878,341 shares issued and outstanding at March 31, 2009 and 2008, respectively		1,191			1,150
Additional paid-in capital		92,582,001			91,790,181
Accumulated deficit		(68,735,029	)		(22,393,688	)
Total stockholders’ equity		23,848,163			69,397,643

Total liabilities and stockholders’ equity	$	35,779,861		$	83,571,181

The accompanying notes are an integral part of these financial statements.

F-3

Rancher Energy Corp.

Statements of Operations

	For the Years Ended March 31,
	2009			2008
Revenue:
Oil and gas sales	$	5,140,660		$	6,344,414
Gains (losses)s on derivative activities		1,020,672			(956,142	)
Total revenues		6,161,332			5,388,272
Operating expenses:
Production taxes		647,755			772,010
Lease operating expenses		2,423,015			2,906,210
Depreciation, depletion, and amortization		1,196,970			1,360,737
Impairment of unproved properties		39,050,000			-
Accretion expense		158,009			121,740
Exploration expense		20,108			223,564
General and administrative		3,631,580			7,538,242
Total operating expenses		47,127,437			12,922,503

Loss from operations		(40,966,105	)		(7,534,231	)

Other income (expense):
Liquidated damages pursuant to registration rights arrangement		-			(2,645,393	)
Amortization of deferred financing costs and discount on note payable		(4,021,767	)		(2,423,389	)
Interest expense		(1,369,957	)		(794,693	)
Interest and other income		16,488			232,880
Total other income (expense)		(5,375,236	)		(5,630,595	)

Net loss	$	(46,341,341	)	$	(13,164,826	)

Basic and diluted net loss per share	$	(0.40	)	$	(0.12	)

Basic and diluted weighted average shares outstanding		116,398,755			109,942,627

The accompanying notes are an integral part of these financial statements.

F-4

Rancher Energy Corp.

Statement of Changes in Stockholders’ Equity

	Shares		Amount		Additional Paid- In Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance, March 31, 2007		102,041,432	$	1,021	$	84,985,934		$	( 9,228,862	)	$	75,758,093

Common stock issued pursuant to registration rights agreement		9,731,569		97		5,463,315			-			5,463,412

Common stock issued on exercise of stock options		1,750,000		18		-			-			18

Common stock issued to directors for services rendered		1,248,197		13		503,787			-			503,800

Common stock issued to non-employee consultant for services rendered		107,143		1		112,499			-			112,500

Offering costs incurred pursuant to registration rights agreement		-		-		(300,365	)		-			(300,365	)

Stock-based compensation		-		-		1,025,011			-			1,025,011

Net loss		-		-		-			( 13,164,826	)		( 13,164,826	)

Balance March 31, 2008		114,878,341	$	1,150	$	91,790,181		$	(22,393,688	)	$	69,397,643

Common stock issued on exercise of stock options		750,000		7		-			-			7

Common stock issued to directors for services rendered		3,388,359		34		217,466			-			217,500

Stock-based compensation		-		-		574,354			-			574,354

Net loss		-		-		-			(46,341,341	)		(46,341,341	)

Balance March 31, 2009		119,016,700	$	1,191	$	92,582,001		$	(68,735,029	)	$	23,848,163

The accompanying notes are an integral part of these financial statements.

F-5

Rancher Energy Corp.

Statements of Cash Flows

	For the Years Ended March 31,
	2009			2008
Cash flows from operating activities:
Net loss	$	(46,341,341	)	$	(13,164,826	)
Adjustments to reconcile net loss to net cash used for operating activities:
Liquidated damages pursuant to registration rights arrangements		-			2,645,393
Imputed interest on registration rights arrangement payments		-			112,489
Depreciation, depletion, and amortization		1,196,970			1,360,737
Impairment of unproved properties		39,050,000			-
Accretion expense		158,009			121,740
Asset retirement obligations settled		(147,662	)		(278,739
Stock-based compensation expense		470,953			1,025,011
Amortization of deferred financing costs and discount on notes payable		4,021,767			2,423,389
Unrealized (gains) losses on crude oil hedges		(1,227,567	)		771,607
Common stock issued for services, directors		320,900			503,800
Common stock issued for services, non-employee		-			112,500
Loss on sale of assets		39,972
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses		586,501			(586,935	)
Accounts payable and accrued liabilities		(1,093,445	)		367,411

Net cash used for operating activities		(2,964,943	)		(4,586,423	)

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(260,735	)		(4,245,011	)
Proceeds from conveyance of unproved oil and gas properties		-			491,500
Increase in other assets		(358,056	)		(927,769	)
Net cash used for investing activities		(618,791	)		(4,681,280	)

Cash flows from financing activities:
Increase in deferred financing costs		(101,478	)		(959,468	)
Proceeds from borrowings		-			12,240,000
Proceeds from issuance of common stock upon exercise of stock options		7			18
Repayment of debt		(2,240,000	)
Payment of offering costs		-			(300,365
Net cash provided by (used for) financing activities		(2,341,471	)		10,980,185

Increase (decrease) in cash and cash equivalents		(5,925,205	)		1,712,482
Cash and cash equivalents, beginning of year		6,842,365			5,129,883
Cash and cash equivalents, end of year	$	917,160		$	6,842,365
Non-cash investing and financing activities:
Cash paid for interest	$	1,369,733		$	682,204
Payables for purchase of oil and gas properties	$	53,799		$	-
Asset retirement asset and obligation	$	10,481		$	213,757
Issuance of common stock in settlement of registration rights arrangement and imputed interest	$	-		$	5,463,412
Discount on note payable, conveyance of overriding royalty interest	$	1,050,000		$	4,500,000

The accompanying notes are an integral part of these financial statements.

F-6

Rancher Energy Corp.

Notes to Financial Statements

Note 1—Organization and Summary of Significant Accounting Policies

Organization

Rancher Energy Corp. (Rancher Energy or the Company), formerly known as Metalex Resources, Inc. (Metalex), was incorporated in Nevada on February 4, 2004. The Company acquires, explores for, develops and produces oil and natural gas, concentrating on applying secondary and tertiary recovery technology to older, historically productive fields in North America.

Metalex was formed for the purpose of acquiring, exploring and developing mining properties. On April 18, 2006, the stockholders of Metalex voted to change its name to Rancher Energy Corp. and announced that it changed its business plan and focus from mining to oil and gas.

From February 4, 2004 (inception) through the third fiscal quarter ended December 31, 2006, the Company was a development stage company. Commencing with the fourth fiscal quarter ended March 31, 2007, the Company was no longer in the development stage.

The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the realization of assets and extinguishment of liabilities in the normal course of business. As shown in the accompanying Statements of Operations, we have incurred a cumulative net loss of $68.7 million for the period from inception (February 4, 2004) to March 31, 2009 and have a working capital deficit of approximately $8.8 million as of March 31, 2009. The Company’s current cash reserves are sufficient to continue operations through the end of September 2009. We require significant additional funding to repay the short term debt in the amount of $10 million, scheduled to mature on October 15, 2009, to continue operations and for our planned oil and gas development operations. The Company’s ability to continue as going concern is dependent upon its ability to obtain additional funding in order to finance its planned operations. The Company is seeking to raise substantial financing through the sale of debt or equity, or to enter into a strategic partnering arrangement with an experienced industry operator to enable it to pay its short term debt, continue operations and to pursue its business plan. There is no assurance the Company will be successful in these efforts. If the Company is not successful in raising substantial funding or closing a strategic partnering transcation to address its cash needs and its short-term debt within the required timeframe, it may need to cease operations and its secured lender may foreclose on its properties and/or a bankruptcy filing could be made. If the Company enters the bankruptcy process, there is no assurance it will be successful in emerging from bankruptcy.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculations of depletion, depreciation, and amortization (DD&A) and impairment, each of which represents a significant component of the financial statements.

Revenue Recognition

The Company derives revenue primarily from the sale of produced crude oil. The Company reports revenue and its net revenue interests as the amount received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 60 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates.

Crude oil sales proceeds and proceeds from derivative settlements are remitted by the crude oil purchaser and the derivative counterparty directly to the Lender under the provisions of the Term Credit Agreement as amended. So long as the Company is current on its obligations to the Lender, the proceeds are then paid by the Lender to the Company on or before the last day of the month of receipt.

F-7

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Concentration of Credit Risk

Substantially all of the Company’s receivables are from purchasers of oil and gas and from joint interest owners. Although diversified among a number of companies, collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized. To date the Company has had no bad debts.

Oil and Gas Producing Activities

The Company uses the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the consolidated statements of cash flows. The costs of development wells are capitalized whether or not proved reserves are found. Costs of unproved leases, which may become productive, are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair value and are not subject to amortization.

Geological and geophysical costs and the costs of carrying and retaining unproved properties are expensed as incurred. DD&A of capitalized costs related to proved oil and gas properties is calculated on a property-by-property basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging equipment.

The Company complies with Statement of Financial Accounting Standards Staff Position No. FAS 19-1, Accounting for Suspended Well Costs, (FSP FAS 19-1). The Company currently does not have any existing capitalized exploratory well costs, and has therefore determined that no suspended well costs should be impaired.

The Company reviews its long-lived assets for impairments when events or changes in circumstances indicate that impairment may have occurred. The impairment test for proved properties compares the expected undiscounted future net cash flows on a property-by-property basis with the related net capitalized costs, including costs associated with asset retirement obligations, at the end of each reporting period. Expected future cash flows are calculated on all proved reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing, adjusted for basis and quality differentials, for the first three to five years and is held constant thereafter. Operating costs are also adjusted as deemed appropriate for these estimates. When the net capitalized costs exceed the undiscounted future net revenues of a field, the cost of the field is reduced to fair value, which is determined using discounted future net revenues. An impairment allowance is provided on unproved property when the Company determines the property will not be developed or the carrying value is not realizable. Recent global market conditions and declining commodity prices have negatively impact the valuation of the Company’s unproved oil and gas properties. During the year ended March 31, 2009, the Company recognized impairment of $39,050,000, representing the excess of the carrying value over the estimated realizable value of such properties. The Company recognized no impairment of unproved properties during the year ended March 31, 2008.

Sales of Proved and Unproved Properties

The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production DD&A rate. A gain or loss is recognized for all other sales of producing properties and is reflected in results of operations.

The sale of a partial interest in an unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to recovery of the cost applicable to the interest retained. A gain on the sale is recognized to the extent the sales price exceeds the carrying amount of the unproved property. A gain or loss is recognized for all other sales of nonproducing properties and is reflected in results of operations. During the year ended March 31, 2008, the Company received proceeds on the sale of unproved properties of $491,500, for which no gain or loss was recognized.

F-8

Capitalized Interest

The Company’s policy is to capitalize interest costs to oil and gas properties on expenditures made in connection with exploration, development and construction projects that are not subject to current DD&A and that require greater than six months to be readied for their intended use (“qualifying projects”). Interest is capitalized only for the period that such activities are in progress. To date the Company has had no such qualifying projects during periods when interest expense has been incurred. Accordingly the Company has recorded no capitalized interest.

Other Property and Equipment

Other property and equipment, such as office furniture and equipment, automobiles, and computer hardware and software, is recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets from three to seven years. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Deferred Financing Costs

Costs incurred in connection with the Company’s debt issuances are capitalized and amortized over the term of the debt, which approximates the effective interest method. Amortization of deferred financing costs of $610,006 and $351,685 was recognized for the years ended March 31, 2009 and 2008 and has been charged to operations as an expense in the Statement of Operations. Unamortized balances of deferred financing costs of $-0- and $508,529 are included in other assets on the Balance Sheets as of March 31, 2009 and 2008, respectively.

Fair Value of Financial Instruments

The Company’s financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Because considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the sale or refinancing of such instruments.

Income Taxes

The Company uses the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities. The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.

The Company adopted the provisions of FIN 48 on April 1, 2007. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS No. 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s financial position and did not result in unrecognized tax benefits being recorded. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions. Accordingly, no corresponding interest and penalties have been accrued. The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. Federal jurisdiction and in the state of Colorado. The Company’s tax years of 2005and forward for Federal, and 2004 and forward for Colorado, are subject to examination by the respective taxing authorities.

Net Loss per Share

Basic net (loss) per common share of stock is calculated by dividing net loss available to common stockholders by the weighted-average of common shares outstanding during each period.

Diluted net income per common share is calculated by dividing adjusted net loss by the weighted-average of common shares outstanding, including the effect of other dilutive securities. The Company’s potentially dilutive securities consist of in-the-money outstanding options and warrants to purchase the Company’s common stock. Diluted net loss per common share does not give effect to dilutive securities as their effect would be anti-dilutive.

F-9

The treasury stock method is used to measure the dilutive impact of stock options and warrants. The following table details the weighted-average dilutive and anti-dilutive securities related to stock options and warrants for the periods presented:

	For the Years Ended March 31,
	2009		2008
Dilutive		-		-
Anti-dilutive		68,091,225		80,665,639

Stock options and warrants were not considered in the detailed calculations below as their effect would be anti-dilutive.

The following table sets forth the calculation of basic and diluted loss per share:

	For the Year Ended March 31,
	2009				2008

Net loss		$	(46,341,341	)		$	(13,164,826	)

Basic weighted average common shares outstanding			116,398,755				109,942,627

Basic and diluted net loss per common share		$	(0.40	)		$	(0.12	)

Share-Based Payment

Effective April 1, 2006, Rancher Energy adopted Statement of Financial Accounting Standard 123(R) “Accounting for Stock-Based Compensation” using the modified prospective transition method. SFAS No. 123R requires companies to recognize compensation cost for stock-based awards based on estimated fair value of the award, effective April 1, 2006. See Note 7 for further discussion. The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with SFAS No.123(R) and the conclusions reached by the Emerging Issues Task Force ("EITF") in Issue No. 96-18. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by EITF 96-18.

Commodity Derivatives

The Company accounts for derivative instruments or hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires the Company to record derivative instruments at their fair value. The Company’s risk management strategy is to enter into commodity derivatives that set “price floors” and “price ceilings” for its crude oil production. The objective is to reduce the Company’s exposure to commodity price risk associated with expected crude oil production.

The Company has elected not to designate the commodity derivatives to which they are a party as cash flow hedges, and accordingly, such contracts are recorded at fair value on its balance sheets and changes in such fair value are recognized in current earnings as income or expense as they occur.

The Company does not hold or issue commodity derivatives for speculative or trading purposes. The Company is exposed to credit losses in the event of nonperformance by the counterparty to its commodity derivatives. It is anticipated, however, that its counterparty will be able to fully satisfy its obligations under the commodity derivatives contracts. The Company does not obtain collateral or other security to support its commodity derivatives contracts subject to credit risk but does monitor the credit standing of the counterparty. The price the Company receives for production in its three fields is indexed to Wyoming Sweet crude oil posted price. The Company has not hedged the basis differential between the NYMEX price and the Wyoming Sweet price. Under the terms of our Term Credit Agreement issued in October 2007 the Company was required hedge a portion of its expected future production, and it entered into a costless collar agreement for a portion of its anticipated future crude oil production. The costless collar contains a fixed floor price (put) and ceiling price (call). If the index price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. The table below summarizes the terms of the Company’s costless collar:

F-10

The table below summarizes the realized and unrealized losses related to the Company’s derivative instruments for the years ended March 31, 2009 and 2008.

	Year Ended March 31,
	2009			2008
Realized gains (losses) on derivative instruments	$	(206,895	)	$	(184,535	)
Unrealized gains (losses) on derivative instruments		1,227,567			(771,607	)
Total realized and unrealized gains (losses) recorded	$	1,020,672		$	(956,142	)

Contract Feature	Contract Term	Total Volume Hedged (Bbls)		Remaining Volume Hedged (Bbls)		Index	Fixed Price ($/Bbl)		Position at March 31, 2009 Due To (From) Company

Put	Nov 07—Oct 09		113,220		31,908	WTI NYMEX	$	65.00	$	455,960
Call	Nov 07—Oct 09		67,935		19,146	WTI NYMEX	$	83.50	$	-

Comprehensive Income (Loss)

The Company does not have revenue, expenses, gains or losses that are reflected in equity rather than in results of operations. Consequently, for all periods presented, comprehensive loss is equal to net loss.

Major Customers

For the years ended March 31, 2009 and 2008, one customer accounted for 100% of the Company’s oil and gas sales. The loss of that customer would not be expected to have a material adverse effect upon our sales and would not be expected to reduce the competition for our oil production, which in turn would not be expected to negatively impact the price we receive. As of March 31, 2009 and 2008 accounts receivable from this customer account for 31% and 41%, respectively of the Company’s total accounts receivable and prepaid expense balances.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, exploitation, development, acquisition, and production of crude oil and natural gas. All of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Off—Balance Sheet Arrangements

As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (SPEs), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. From February 4, 2004 (inception) through March 31, 2009, the Company has not been involved in any unconsolidated SPE transactions.

Reclassification

Certain amounts in the 2008 financial statements have been reclassified to conform to the 2009 financial statement presentation. Such reclassifications had no effect on net loss.

F-11

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. On April 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. On April 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We do not expect the provisions of SFAS No. 157 related to these items to have a material impact on our consolidated financial statements (see Note 4).

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for the Company’s financial statements April 1, 2008 and the adoption had no material effect on our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for the Company’s fiscal year beginning April 1, 2009. We do not expect the adoption of SFAS No. 141R to have a material impact on our consolidated financial statements.

In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 defines “right of setoff” and specifies what conditions must be met for a derivative contract to qualify for this right of setoff. It also addresses the applicability of a right of setoff to derivative instruments and clarifies the circumstances in which it is appropriate to offset amounts recognized for those instruments in the statement of financial position. In addition, this FSP permits offsetting of fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement and fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. We adopted this interpretation on April 1, 2008 and the adoption of FSP FIN 39-1 had no material effect on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 161 on our future financial reporting.

In June 2008, the Emerging Issues Task Force (“Task Force”) issued EITF 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock.” The objective of this Issue is to provide guidance for determining whether an equity-linked financial instrument (or embedded feature) is indexed to an entity’s own stock. The Task Force reached a consensus that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. Additionally, denomination of an equity contract’s strike price in a currency other than the entity’s functional currency is inconsistent with equity indexation and precludes equity treatment. We adopted EITF 07-5 on April 1, 2009 and the adoption had no material effect on our financial position or results of operations.

F-12

On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending March 31, 2010. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:

•

The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.

•

Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.

•

Many of our financial reporting disclosures could change as a result of the new rules.

Note 2—Oil and Gas Properties

The Company’s oil and gas properties are summarized in the following table:

	As of March 31,
	2009			2008
Proved properties	$	20,631,487		$	20,734,143

Unimproved properties excluded from DD&A		52,953,185			53,655,471
Equipment and other		374,962			402,602
Subtotal Unevaluated Properties		53,328,147			54,058,073
Total oil and gas properties		73,959,634			74,792,216
Less accumulated depletion, depreciation, amortization and impairment		(41,840,978	)		(1,531,619	)
	$	32,118,656		$	73,260,597

Assignment of Overriding Royalty Interest

In conjunction with the issuance of short term debt in October 2007 (See Note 5),the Company assigned the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated that the fair value of the ORRI granted to the Lender to be approximately $4,500,000 and recorded this amount as a debt discount and a decrease of oil and gas properties. In October 2008 the Company extended the maturity date of the short term debt by six months. As partial consideration for the extension, the Company granted an increase the proportionate ORRI from 2% to 3%. The Company estimated that the fair value of the incremental ORRI granted to the Lender to be approximately $1,050,000 and has recorded this amount as a debt discount and a decrease of oil and gas properties.

Acquisitions

Cole Creek South Field and South Glenrock B Field Acquisitions

On December 22, 2006, the Company purchased certain oil and gas properties for $46,750,000, before adjustments for the period from the effective date to the closing date, and closing costs. The oil and gas properties consisted of (i) a 100% working interest (79.3% net revenue interest) in the Cole Creek South Field, which is located in Wyoming’s Powder River Basin; and (ii) a 93.6% working interest (74.5% net revenue interest) in the South Glenrock B Field, which is also located in Wyoming’s Powder River Basin.

In addition to the cash consideration paid of the two fields, the Company issued the seller of the oil and gas properties warrants to acquire 250,000 shares of its common stock for $1.50 per share for a period of five years. The fair value of the warrants to purchase common stock as of the grant date was estimated to be $616,140 using the Black-Scholes option pricing.

Big Muddy Field Acquisition

On January 4, 2007, Rancher Energy acquired the Big Muddy Field, consisting of approximately 8,500 acres located in the Powder River Basin east of Casper, Wyoming. The total purchase price was $25,000,000, before adjustments for the period from the effective date to the closing date, and closing costs. While the Big Muddy Field was discovered in 1916, future profitable operations are dependent on the application of tertiary recovery techniques requiring significant amounts of CO2.

F-13

Carbon Dioxide (“CO2”) Enhanced Oil Recovery Project

The Company’s business plan includes the injection of CO2 into its three oil fields in the Powder River Basin. To ensure an adequate supply of CO2 the Company has entered into two separate supply agreements as follows:

Anadarko Agreement

On December 15, 2006, the Company executed a Product Sale and Purchase Contract (Purchase Contract) with the Anadarko Petroleum Corporation (Anadarko) for the purchase of CO2 (meeting certain quality specifications identified in the agreement) from Anadarko. The primary term of the Agreement commences upon the later of January 1, 2008, or the date of the first CO2 delivery, and terminates upon the earlier of the day on which the Company has taken and paid for the Total Contract Quantity, as defined, or 10 years from the commencement date. The Company has the right to terminate the Purchase Contract at any time with notice to Anadarko, subject to a termination payment as specified in the Purchase Contract. During the primary term the “Daily Contract Quantity” is 40 MMcf per day for a total of 146 Bcf. Carbon Dioxide (CO2) deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko has the right to satisfy its own needs before sales to the Company, which reduces our take-or-pay obligation. In the event the CO2 does not meet certain quality specifications, we have the right to refuse delivery of such CO2 For CO2 deliveries, the Company has agreed to pay $1.50 per thousand cubic feet, to be adjusted by a factor that is indexed to the average posted price of Wyoming Sweet oil. From oil that is produced by CO2 injection, the Company also agreed to convey to Anadarko an overriding royalty interest of 1% in year one, increasing 1% on each of the next four anniversaries to a maximum of 5% for the remainder of the 10-year term.

Exxon/Mobil Agreement

On February 12, 2008 the Company entered into a Carbon Dioxide Sale and Purchase Agreement (Sale and Purchase Agreement) with ExxonMobil Gas & Power Marketing Company (“ExxonMobil”), a division of Exxon Mobil Corporation, under which ExxonMobil will provide Rancher Energy with 70 MMscfd (million standard cubic per day) of CO2 for an initial 10-year period, with an option for a second 10 years. The CO2 will be supplied from ExxonMobil’s LaBarge gas field in Wyoming. For CO 2 deliveries from ExxonMobil, the Company has agreed to pay a base price plus an Oil Price Factor which is indexed to the price of West Texas Intermediate crude oil.

On March 18, 2009, the Company, entered into an Assignment Agreement (the “Assignment”) with an unrelated third party operator (the “Operator”), for the assignment by the Company of a portion of its right, title and interest in and to, and the assumption by the Operator of the Company’s obligations related thereto, the Sale and Purchase Agreement. ExxonMobil has consented to the Assignment. Under the terms of the Assignment, the Operator may purchase up to 37.5 MMCF per day of carbon dioxide from ExxonMobil for a two-year term beginning on the Start-up Date, as defined in the Contract (the “Initial Term”). ExxonMobil will deliver the contract quantities to the existing delivery point at the interconnect of the ExxonMobil and the Operator’s pipelines near Bairoil, Wyoming.

The terms of the Assignment also provide the Operator with an option to purchase an additional 6.5 MMCF per day during the Initial Term. Following the Initial Term, to the extent the Company is not using for its own tertiary recovery purposes any volumes of carbon dioxide the Company is otherwise obligated, or able to purchase from ExxonMobil under the Sale and Purchase Agreement, the Operator has the option to purchase from the Company so much of such volumes as it elects on a monthly basis. If, during any period in which the Operator is purchasing carbon dioxide volumes under either of these options, an Event of Default (as defined in the Assignment) occurs, the Company will be required, at the Operator’s sole discretion but subject to ExxonMobil’s rights and remedies under the Sale and Purchase Agreement, to assign its remaining rights under the Contract to the Operator.

See Note 12, Subsequent Events, for further discussion of ExxonMobil’s purported termination of the Sale and Purchase Agreement subsequent to March 31, 2009.

Impairment of Unproved Properties

In conjunction with the regular periodic assessment of impairment of unproved properties, the Company re-evaluated the carrying value of its unproved properties giving consideration to lower commodity prices and the difficulties encountered in raising capital to develop the properties. Accordingly, during the year ended March 31, 2009 the Company recorded $39,050,000 of impairment expense on unproved properties, reflecting the excess of the carrying value over estimated realizable value of the assets. The Company recorded no impairment of unproved properties in the year ended March 31, 2008.

F-14

Exploration of Strategic Alternatives

In August 2008, the Company retained a financial advisor to assist in exploring financing and other strategic alternatives, including the possible sale of the Company. The Company has not been successful in completing such a strategic transaction. Our ability to survive will be dependent upon completing a strategic transaction; however, there is no assurance any such transaction will be completed.

Note 3—Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s statement of cash flows.

The Company’s estimated asset retirement obligation liability is based on our historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and Federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rate used to discount the Company’s abandonment liabilities was 13.1%. Revisions to the liability are due to changes in estimated abandonment costs and changes in well economic lives, or if Federal or state regulators enact new requirements regarding the abandonment of wells.

A reconciliation of the Company’s asset retirement obligation liability during the years ended March 31, 2009 and 2008 is as follows:

	2009			2008
Beginning asset retirement obligation	$	1,259,851		$	1,221,567
Liabilities incurred		-			18,473
Liabilities settled		(147,662	)		(297,212
Changes in estimates		10,482			195,283
Accretion expense		158,009			121,740
Ending asset retirement obligation	$	1,280,680		$	1,259,851

Current	$	108,884		$	337,685
Long-term		1,171,796			922,166
	$	1,280,680		$	1,259,851

Note 4 Fair Value Measurements

On April 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The Statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

F-15

SFAS No. 157 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008 by level within the fair value hierarchy:

	Fair Value Measurements Using

	Level 1			Level 2			Level 3

Assets:
Derivative instrument		$	-		$	-		$	455,960
Liabilities		$	-		$	-		$	-

The Company’s sole derivative financial instrument is a participating cap costless collar agreement. The fair value of the costless collar agreement is determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in these valuation models are considered level 3 inputs in the fair value hierarchy. In the Company’s adoption of SFAS No. 157, it considered the impact of counterparty credit risk in the valuation of its assets and its own credit risk in the valuation of its liabilities that are presented at fair value. The Company established the fair value of its derivative instruments using a published index price, the Black-Scholes option-pricing model and other factors including volatility, time value and the counterparty’s credit adjusted risk free interest rate. The actual contribution to the Company’s future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at March 31, 2009.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy:

	Derivatives				Total
Balance as of April 1, 2008, asset, (liability)		$	(836,907	)		$	(836,907	)
Total gains (losses) (realized or unrealized):
Included in earnings			1,020,673				1,020,673
Included in other comprehensive income
Purchases, issuances and settlements			272,194				272,194
Transfers in and out of Level 3

Balance as of March 31, 2009		$	455,960			$	455,960

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of March 31, 2009		$	1,292,867			$	1,292,867

Note 5—Short Term Note Payable

On October 16, 2007, the Company issued a Note Payable (the Note) in the amount of $12,240,000 pursuant to a Term Credit Agreement with a financial institution (the Lender). All amounts outstanding under the Note were originally due and payable on October 31, 2008 (Maturity Date) and bore interest at a rate equal to the greater of (a) 12% per annum and (b) the one-month LIBOR rate plus 6% per annum. The Note was amended on October 22, 2008, (the “First Amendment”), to extend the maturity date by six months from October 31, 2008 to April 30, 2009. In consideration of the six month extension and other terms included in First Amendment, the Company made a principal payment to the Lender in the amount of $2,240,000, resulting in a new loan balance of $10,000,000. As more fully discussed in Note 12, Subsequent Events, after March 31, 2009, the Company and the Lender entered into several amendments to the Term Credit Agreement to further extend the term.

Under the terms of the Credit Agreement, as amended, the Company is required to make monthly interest payments on the amounts outstanding but is not required to make any principal payments until the Maturity Date. The Company may prepay the amounts outstanding under the Credit Agreement at any time without penalty. As of March 31, 2009 the interest rate on the Note is 12% per annum.

The Company’s obligations under the Credit Agreement, as amended, are collateralized by a first priority security interest in its properties and assets, including all rights under oil and gas leases in its three producing oil fields in the Powder River Basin of Wyoming and all of its equipment on those properties. Under the terms of the original Term Credit Agreement, the Company granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The First Amendment granted an increase in the proportionate overriding royalty interests (“ORRI”) assigned to the Lender from 2% to 3%. The Company estimated the fair value of the 2% ORRI granted to the Lender to be approximately $4,500,000 and the value of the increase ORRI to be approximately $1,050,000. These amounts were recorded as discounts to the Note Payable and as decreases of oil and gas properties. Amortization of the discounts based upon the effective interest method in the amounts of $ 3,411,761 and $1,972,450 is included in interest expense for years ended March 31, 2009 and 2008, respectively. As long as any of its obligations remain outstanding under the Credit Agreement, as amended,, the Company will be required to grant the same ORRI to the Lender on any new working interests acquired after closing. Under the terms of the First Amendment, the Company has the right to buy back one-third (1/3) of the ORRI at a repurchase price calculated to ensure that total payments by the Company to the Lender of principal, interest, ORRI revenues, and ORRI repurchase price will equal 140% of the original loan amount.

F-16

The Credit Agreement, as amended, contains several events of default, including if, at any time after closing, the Company’s most recent reserve report indicates that its projected net revenue attributable to proved reserves is insufficient to fully amortize the amounts outstanding under the Credit Agreement within a 48-month period and it is unable to demonstrate to the Lender’s reasonable satisfaction that it would be able to satisfy such outstanding amounts through a sale of its assets or a sale of equity. Upon the occurrence of an event of default under the Credit Agreement, the Lender may accelerate the Company’s obligations under the Credit Agreement. Upon certain events of bankruptcy, obligations under the Credit Agreement would automatically accelerate. In addition, at any time that an event of default exists under the Credit Agreement, the Company will be required to pay interest on all amounts outstanding under the Credit Agreement at a default rate, which is equal to the then-prevailing interest rate under the Credit Agreement plus four percent per annum.

The Company is subject to various restrictive covenants under the Credit Agreement, including limitations on its ability to sell properties and assets, pay dividends, extend credit, amend material contracts, incur indebtedness, provide guarantees, effect mergers or acquisitions (other than to change its state of incorporation), cancel claims, create liens, create subsidiaries, amend its formation documents, make investments, enter into transactions with its affiliates, and enter into swap agreements. The Company must maintain (a) a current ratio of at least 1.0 (excluding from the calculation of current liabilities any loans outstanding under the Credit Agreement) and (b) a loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As of March 31, 2009 and the date of this Annual Report, the Company was not in compliance with the loan-to-value ratio covenant, primarily due to a lower crude oil price deck used in computing the reserve value. The lender has waived this non-compliance from March 31, 2009 through the amended maturity date, October 15, 2009.

Note 6—Commitments and Contingencies

The Company leases office space under a non-cancelable operating lease that expires July 31, 2012. Rent expense was $363,700 and $278,625 during the years ended March 31, 2009 and 2008 respectively. The annual minimum lease payments for the next five fiscal years and thereafter are presented below:

Years Ending March 31,

202 2010	$	367,334
201 2011		379,715
201 2012		383,842
T Thereafter		127,947
Total	$	1,258,838

The Company has entered into CO2 supply agreements with Anadarko and ExxonMobil as discussed in Note 2 above. The Company has also entered into a Registration Rights Agreement as discussed in Note 7 below.

Threatened Litigation

On December 31, 2008, we received a letter from an attorney representing Sergei Stetsenko and other shareholders (the “Stetsenko Group”) stating that it was the opinion of the Stetsenko Group that our Directors and Executive Officers have acted negligently and contrary to their fiduciary duties. The letter threatens a lawsuit and demands that the Directors and our Executive Officers return all cash and stock received from us, cease payment of any cash or stock compensation for their services, resign their positions as Directors and Executive Officers and call a shareholders’ meeting to elect Andrei Stytsenko as the sole director of the Company. No suit has been filed. We deny the allegations and believe that they are without merit. In February 2009, our Board of Directors established a Special Committee of the Board (the “Special Committee”) to investigate the allegations. The Stetsenko Group has informed us that it intends to propose an alternate slate of directors at the next meeting of shareholders. We cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit.

F-17

In a letter dated February 18, 2009 sent to each of our Directors, attorneys representing a group of persons who purchased approximately $1,800,000 of securities (in the aggregate) in our private placement offering commenced in late 2006 alleged that securities laws were violated in that offering. Subsequent to March 31, 2009, we entered into tolling agreements with the purchasers to toll the statutes of limitations applicable to any claims related to the private placement. Our Board of Directors directed the Special Committee to investigate these allegations. The Company believes the allegations are without merit. We cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit..

Note 7—Stockholders’ Equity

The Company’s capital stock as of March 31, 2009 and 2008 consists of 275,000,000 authorized shares of common stock, par value $0.00001 per share.

Issuance of Common Stock

For the Year Ended March 31, 2009

During the year ended March 31, 2009, the Company issued common stock as follows:

750,000 shares to an officer of the Company upon the exercise of stock options;

3,388,359 shares to directors of the Company in exchange for services;

For the Year Ended March 31, 2008

During the year ended March 31, 2008, the Company issued common stock as follows:

	-	9,731,569 shares to holders of registrable shares of the December 2006 and January 2007 private placements, as liquidated damages in settlement of registration rights deficiencies (see Registration Rights and Other Payment Arrangements below);
	-	1,750,000 shares to an officer of the Company upon the exercise of stock options;

1,248,197 shares to directors of the Company in exchange for services;

107,143 shares to independent consultant in exchange for services

Warrants

In connection with sale of common stock and other securities in the fiscal year ended March 31, 2007, the Company issued warrants to purchase shares of common stock. The following is a summary of warrants outstanding as of March 31, 2009

	Warrants	Exercise Price		Expiration Date
Warrants issued in connection with the following:

Private placement of common stock	45,940,510	$	1.50	March 30, 2012

Private placement of convertible notes payable	6,996,322	$	1.50	March 30, 2012

Private placement agent commissions	1,445,733	$	1.50	March 30, 2012

Acquisition of oil and gas properties	250,000	$	1.50	December 22, 2011

Total warrants outstanding at March 31, 2008	54,632,565

F-18

Registration and Other Payment Arrangements

In connection with the private placement sale of the Company’s common stock and other securities during the fiscal year ended March 31, 2007, the Company entered into Registration Rights Agreements (the “Agreements”) under which the Company agreed to register for resale the shares of common stock issued in the private placement as well as the shares underlying the other securities. Under the terms of the Agreements the Company must pay the holders of the registrable securities issued in the private placement, liquidated damages if the registration statement that was filed in conjunction with the private placement was not declared effective by the U.S. Securities and Exchange Commission (SEC) within 150 days of the closing of the private placement (December 21, 2006). The liquidated damages were due on or before the day of the failure (May 20, 2007) and every 30 days thereafter, or three business days after the failure is cured, if earlier. The amount due was 1% of the aggregate purchase price, or $794,000 per month. If the Company fails to make the payments timely, interest accrues at a rate of 1.5% per month. Payments pursuant to the Registration Rights Agreement and the private placement agreement are limited to 24% of the aggregate purchase price, or $19,057,000 in total. The payment may be made in cash, notes, or shares of common stock, at the Company’s option, as long as the Company does not have an equity condition failure. The Company’s registration statement was not declared effective prior to the May 20, 2007 failure date and pursuant to the terms of the Registration Rights Agreement, the Company opted to pay the liquidated damages in shares of common stock. The number of shares issued was based on the payment amount of $794,000 divided by 90% of the volume weighted average price of the Company’s common stock for the 10 trading days immediately preceding the payment due.

Using the above formula, the Company made delay registration effectiveness payments between May 18, 2007 and October 31, 2007 by issuing a total of 9,731,569 shares of its common stock at prices ranging from $0.85- $0.43 per share.

The Company’s registration statement was declared effective on October 31, 2007. Since that date the Company has maintained the effectiveness of the registration statement and complied with all other provisions of the Registration Rights Agreement. No further liquidated damages have been assessed or paid. In accordance with FSP EITF 00-19-2, Accounting for Registration Payment Arrangements, as of the date of this Annual Report, the Company believes the likelihood it will incur additional obligations to pay liquidated damages is remote, as defined in SFAS 5, Accounting for Contingencies. Accordingly as of March 31, 2009 and 2008, the Company has not recorded a liability for future liquidated damages under the Registration Rights Agreement.

Note 8—Share-Based Compensation

Effective April 1, 2006, the Company adopted Statement of Financial Accounting Standard 123(R) (SFAS 123(R)), Share-Based Payment . SFAS No. 123(R) requires companies to recognize share-based payments to employees as compensation expense using a fair value method. Under the fair value recognition provisions of SFAS No. 123(R), stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period on a straight-line basis, which generally represents the vesting period. The Company did not recognize a tax benefit from the stock compensation expense because it is more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be realized.

The Black-Scholes option-pricing model was used to estimate the option fair values. The option-pricing model requires a number of assumptions, of which the most significant are the stock price at the valuation date, the expected stock price volatility, and the expected option term (the amount of time from the grant date until the options are exercised or expire).

Prior to the adoption of SFAS 123(R), the Company reflected tax benefits from deductions resulting from the exercise of stock options as operating activities in the statements of cash flows. SFAS 123(R) requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS 123(R). As a result of the Company’s net operating losses, the excess tax benefits, which would otherwise be available to reduce income taxes payable, have the effect of increasing the Company’s net operating loss carry forwards. Accordingly, because the Company is not able to realize these excess tax benefits, such benefits have not been recognized in the statements of cash flows for the years ended March 31, 2009 and 2008 .

F-19

Chief Executive Officer (CEO) Option Grant

On May 15, 2006, in connection with an employment agreement, the Company granted its President & CEO options to purchase up to 4,000,000 shares of Company common stock at an exercise price of $0.00001 per share. The options vest as follows: (i) 1,000,000 shares upon execution of the employment agreement, (ii) 1,000,000 shares from June 1, 2006 to May 31, 2007 at the rate of 250,000 shares per completed quarter of service, (iii) 1,000,000 shares from June 1, 2007 to May 31, 2008 at the rate of 250,000 shares per completed quarter of service, and (iv) 1,000,000 shares from June 1, 2008 to May 31, 2009 at the rate of 250,000 shares per completed quarter of service. In the event the employment agreement is terminated, the CEO will be allowed to exercise all options that are vested. All unvested options shall be forfeited. The options have no expiration date.

The Company determined the fair value of the options to be $0.4235 per underlying common share. The value was determined by using the Black-Scholes valuation model using assumptions which resulted in the value of one Unit (one common share and one warrant to purchase a common share) equaling $0.50, the price of the most recently issued securities at the date of grant of the options. The combined value was allocated between the value of the common stock and the value of the warrant. The value of one common share from this analysis ($0.4235) was used to calculate the resulting compensation expense under the provisions of SFAS 123(R). The assumptions used in the valuation of the CEO options were as follows:

Volatility		87.00	%
Expected option term	One year
Risk-free interest rate		5.22	%
Expected dividend yield		0.00	%

The expected term of options granted was based on the expected term of the warrants included in the Units described above. The expected volatility was based on historical volatility of the Company’s common stock price. The risk free rate was based on the one-year U.S Treasury bond rate for the month of July 2006.

The Company recognized stock compensation expense attributable to the CEO options of $423,500 for each of the fiscal years ended March 31, 2009 and 2008. The Company expects to recognize the remaining compensation expense of $105,875 related to the unvested shares in the next fiscal year ending March 31, 2010.

2006 Stock Incentive Plan

On March 30, 2007, the 2006 Stock Incentive Plan (the 2006 Stock Incentive Plan) was approved by the shareholders and was effective October 2, 2006. The 2006 Stock Incentive Plan had previously been approved by the Company’s Board of Directors. Under the 2006 Stock Incentive Plan, the Board of Directors may grant awards of options to purchase common stock, restricted stock, or restricted stock units to officers, employees, and other persons who provide services to the Company or any related company. The participants to whom awards are granted, the type of awards granted, the number of shares covered for each award, and the purchase price, conditions and other terms of each award are determined by the Board of Directors, except that the term of the options shall not exceed 10 years. A total of 10,000,000 shares of Rancher Energy common stock are subject to the 2006 Stock Incentive Plan. The shares issued for the 2006 Stock Incentive Plan may be either treasury or authorized and unissued shares. During the year ended March 31, 2009 no options were granted under the 2006 Stock Incentive Plan. During the year ended March 31, 2008 , options to purchase up to 753,000 shares of common stock were granted under the 2006 Stock Incentive Plan to officers, directors, employees and a consultant. The options granted have exercise prices ranging from $0.39 to $1.64 generally vest over three years, and have a maximum term of ten years.

The fair value of the options granted during fiscal 2008, under the 2006 Stock Incentive Plan was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions:

		2008
Expected Volatility		59.80% - 62.75%
Expected option term		3.0 - 6.25 years
Risk-free interest rate		4.39% to 4.68
Expected dividend yield		0.00%

F-20

Because the Company is newly public with an insufficient history of stock price for the expected term, the expected volatility was based on an average of the volatility disclosed by other comparable companies who had similar expected option terms. The expected term of options granted was estimated in accordance with the simplified method prescribed in SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No 110. The risk free rate was based on the five-year U.S Treasury bond rate.

The following table summarizes stock option activity for the year ended March 31, 2009 and 2008:

	2009					2008

	Number of Options			Weighted Average Exercise Price		Number of Options		Weighted Average Exercise Price


Outstanding at beginning of year:
CEO		1,250,000		$	0.00001		3,000,000	$	0.00001
Plan		1,431,000		$	1.74		3,335,000	$	2.34
Granted
CEO		-			-		-		-
Plan		-			-		753,000	$	0.73
Exercised
CEO		(750,000	)	$	0.00001		(1,750,000	$	0.00001
Plan		-			-		-		-
Cancelled
CEO		-			-		-		-
Plan		(855,000	)	$	1.73		(2,657,000	$	2.46
Outstanding at March 31
CEO		500,000		$	0.00001		1,250,000	$	0.00001
Plan		576,000		$	0.61		1,431,000	$	1.28
Exercisable at March 31,
CEO		250,000		$	0.00001		-	$	0.00001
Plan		210,000		$	0.71		430,000	$	1.74

The following table summarizes information related to the outstanding and vested options as of March 31, 2009

	Outstanding Options			Vested Options
Number of Shares
CEO		500,000				250,000
Plan		576,000				210,000
Weighted Average Remaining Contractual Life in Years
CEO	NA - CEO Options Do Not Expire
Plan		3.77				3.54
Weighted Average Exercise Price
CEO	$	0.00001			$	0.00001
Plan	$	0.61			$	0.71
Aggregate Intrinsic Value
CEO	$	9,995			$	4,997
Plan	$	(337,410	)		$	(144,871	)

F-21

The following table summarizes changes in the unvested options for the years ended March 31, 2009 and 2008:

	Number of Options			Weighted Average Grant Date Fair Value

Non-vested, April 1, 2007
CEO		2,250,000		$	0.42
Plan		3,147,500		$	1.54
Total		5,397,500		$	1.07

Granted—
Plan		753,000		$	0.34

Vested—
CEO		(1,000,000	)	$	0.42
Plan		(742,500	)	$	0.75
Total		(1,742,500	)	$

Cancelled - Plan		(2,157,000	)	$	0.67

Non-vested, March 31, 2008
CEO		1,250,000		$	0.42
Plan		1,001,000		$	0.50
Total		2,251,000			0.46

Granted—
CEO		-			-
Plan		-			-
Total		-			-

Vested—
CEO		(1,000,000	)	$	0.42
Plan		(190,000	)	$	0.28
Total		(1,190,000	)	$	0.40

Cancelled - Plan		(445,000	)	$	0.78

Non-vested, March 31, 2009
CEO		250,000		$	0.42
Plan		366,000		$	0.27
Total		616,000		$	0.33

The weighted-average grant-date fair values of the stock options granted during the year ended March 31, 2008 was $0.34. The total intrinsic value, calculated as the difference between the exercise price and the market price on the date of exercise of all options exercised during the years ended March 31, 2009 and 2008, was approximately $162,500 and $1,410,000, respectively. The Company received $8 and $18 from stock options exercised during the year ended March 31, 2009 and 2008, respectively. The Company did not realize any tax deductions related to the exercise of stock options during year.

Total estimated unrecognized compensation cost from unvested stock options as of March 31, 2009 was approximately $204,200 which the Company expects to recognize over the next three years.

F-22

Note 9—Income Taxes

The effective income tax rate for the years ended March 31, 2009 and 2008 differs from the U.S. Federal statutory income tax rate due to the following:

	For the Year Ended March 31,
	2009			2008

Federal statutory income tax rate	$	(16,219,000	)	$	(4,608,000	)
State income taxes, net of Federal benefit		(49,000	)		(33,000	)
Permanent items		18,000			362,000
Other		35,000			(129,000	)
Change in valuation allowance		16,215,000			4,408,000
	$	-		$	-

The components of the deferred tax assets and liabilities as of March 31, 2009 and 2008 are as follows:

	For the Year Ended March 31,
	2009			2008
Long-term deferred tax assets:
Federal net operating loss carryforwards		9,266,000			5,984,000
Asset retirement obligation		449,000			444,000
Stock-based compensation		616,000			469,000
Accrued vacation		22,000			23,000
Unrealized hedging losses (gains)		(160,000	)		272,000
Property , plant and equipment		13,475,000			261,000
Valuation allowance		(23,668,000	)		(7,453,000	)
Net long-term deferred tax assets	$	-		$	-

The Company has approximately $26,400,000 of net operating loss carryovers as of March 31, 2009. The net operating losses begin to expire in 2024.

The Company has provided a full valuation allowance for the deferred tax assets as of March 31, 2009 and 2008, based on the likelihood of the realization of the deferred tax assets will not be utilized in the future.

Note 10—Disclosures about Oil and Gas Producing Activities

Costs Incurred in Oil and Gas Producing Activities:

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows.

	For the Year Ended March 31,
	2009		2008

Exploration	$	20,108	$	223,564
Development		245,172		4,758,783
Acquisitions:
Unproved		-		43,088
Proved		-		-
Total		265,280		5,025,435

Costs associated with asset retirement obligations	$	10,481	$	213,756

F-23

Oil and Gas Reserve Quantities (Unaudited):

For the years ended March 31, 2009 and 2008, Ryder Scott Company, L.P. prepared the reserve information for the Company’s Cole Creek South, South Glenrock B, and Big Muddy Fields in the Powder River Basin.

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and gas reserves, as defined in Regulation S-X, Rule 4-10(a)(2)(3)(4), are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

Presented below is a summary of the changes in estimated oil reserves (in barrels) of the Company for the years ended March 31, 2009 and 2008 (the Company does not have any natural gas reserves).

Total proved:	2009			2008
Beginning of year		1,300,396		1,279,164
Purchases of minerals in-place		-		-
Production		(65,308	)	(86,626	)
Revisions of previous estimates		(68,386	)	107,858
End of year		1,166,702		1,300,396

Proved developed reserves:		955,151		1,074,830

Standardized Measure of Discounted Future Net Cash Flows (Unaudited):

SFAS No. 69, Disclosures about Oil and Gas Producing Activities (SFAS No. 69), prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in effect at year-end to the year-end estimated quantities of oil and gas to be produced in the future. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved oil and gas reserves in place at the end of the period, using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. The price, as adjusted for transportation, quality, and basis differentials, used in the calculation of the standardized measure was $44.75 and $95.49 per barrel of oil for the years ended March 31, 2009 and 2008, respectively. The Company does not have natural gas reserves.

F-24

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS No. 69:

	As of March 31, 2009			As of March 31, 2008

Future cash inflows	$	52,217,000		$	124,164,000
Future production costs		(29,024,000	)		(58,283,000	)
Future development costs		(2,007,000	)		(2,007,000	)
Future income taxes		-			-
Future net cash flows		21,186,000			63,874,000
10% annual discount		(12,462,000	)		(32,946,000	)
Standardized measure of discounted future net cash flows	$	8,724,000		$	30,928,000

The principal sources of change in the standardized measure of discounted future net cash flows are:

	For the year ended March 31, 2008			For the year ended March 31, 2007

Standardized measure of discounted future net cash flows, beginning of year	$	30,928,000		$	13,119,000
Sales of oil and gas produced, net of production costs		(2,070,000	)		(2,666, 000	)
Net changes in prices and production costs		(20,285,000	)		17,737,000
Purchase of minerals in-place		-			-
Revisions of previous quantity estimates		(666,000	)		2,464,000
Accretion of discount		3,093,000			1,312,000
Changes in timing and other		(2,276,000,	)		(1,038,000	)
Standardized measure of discounted future net cash flows, end of year	$	8,724,000		$	30,928,000

Note 11—Related Party Transaction

There were no related party transactions during the years ended March 31, 2009 or 2008.

Note 12—Subsequent Events

As discussed in Note 5, Short Term Note Payable, the Company’s short term debt was scheduled to mature on April 30, 2009. Subsequent to March 31, 2009, the Company and the Lender entered into a series of five amendments (the Second Amendment through the Seventh Amendment) each of which included short term extensions of the maturity date while the definitive terms of the Eighth Amendment were finalized. On June 3, 2009 the Company and the Lender entered into an Eighth Amendment to Term Credit Agreement (“Eighth Amendment”) that amends certain provisions of the Term Credit Agreement dated as of October 16, 2007 pursuant to which Rancher Energy borrowed $12,240,000 from GasRock, certain provisions of the First Amendment to Term Credit Agreement dated October 22, 2008 pursuant to which Rancher Energy repaid $2,240,000, and certain provisions of the Second through Seventh Amendments.

The Eighth Amendment extends the maturity date under the Seventh Amendment from June 3, 2009 to October 15, 2009. In consideration of the amendments contemplated by the Eighth Amendment, the Company executed and delivered a Net Profit Interest Conveyance granting to the Lender a net profits interest in and to the Company’s properties equal to 10% of the net profit attributable to the Company’s interest in and to all hydrocarbons produced or saved from its properties. Under the terms of the Eighth Amendment, the Company has the right to purchase from the Lender: (a) two-thirds (2/3), but not less, of the net profits interest for the period beginning on June 3, 2009 and ending on August 7, 2009 for the sum of $2,000,000 in cash; or (b) for the period beginning August 8, 2009 and ending on October 15, 2009, one-third (1/3), but not less, for the sum of $1,333,333 in cash. Under the terms of the Eighth Amendment, all amounts outstanding under the Term Credit Agreement, as amended, bear interest at a rate equal to the greater of (a) 16% per annum and (b) the LIBOR rate, plus 6% per annum (the LIBOR Margin). Furthermore, the Eighth Amendment specifies that 4% of the interest rate shall be capitalized so that it is added to and becomes a part of the Principal Amount in lieu of payment in cash. The Eighth Amendment also includes waivers by the Lender of certain events of default including the Loan to Value Ratio and the Projected Net Revenue 48 month test as set forth in the Term Credit Agreement, for the period beginning March 31, 2009 and ending on the maturity date.

On April 3, 2009, ExxonMobil informed the Company, that ExxonMobil was terminating, effective immediately, the Sale & Purchase Agreement. ExxonMobil’s purported termination is based on the Company not providing performance assurances in the form of a letter of credit. The Company believes that the Agreement does not obligate the Company to provide any performance assurances until the start-up of CO 2 delivery, which will not occur in 2009. Accordingly, the Company disagrees with ExxonMobil’s rationale for purportedly terminating the Agreement and believes in good faith that Exxon’s termination of the Agreement has not occurred pursuant to the terms of the Agreement and is unlawful. The Company has informed ExxonMobil of its position. If ExxonMobil does not deliver CO2 in accordance with the Sale & Purchase Agreement, the Company may not be able to fully carry out its EOR projects on our three fields.

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